[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2009 Edition]
[From the U.S. Government Printing Office]



[[Page i]]

          

40


          Parts 50 to 51

          Revised as of July 1, 2009


          Protection of Environment
          



________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2009
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

          U.S. GOVERNMENT OFFICIAL EDITION NOTICE

          Legal Status and Use of Seals and Logos
          
          
          The seal of the National Archives and Records Administration 
              (NARA) authenticates the Code of Federal Regulations (CFR) as 
              the official codification of Federal regulations established 
              under the Federal Register Act. Under the provisions of 44 
              U.S.C. 1507, the contents of the CFR, a special edition of the 
              Federal Register, shall be judicially noticed. The CFR is 
              prima facie evidence of the original documents published in 
              the Federal Register (44 U.S.C. 1510).

          It is prohibited to use NARA's official seal and the stylized Code 
              of Federal Regulations logo on any republication of this 
              material without the express, written permission of the 
              Archivist of the United States or the Archivist's designee. 
              Any person using NARA's official seals and logos in a manner 
              inconsistent with the provisions of 36 CFR part 1200 is 
              subject to the penalties specified in 18 U.S.C. 506, 701, and 
              1017.

          Use of ISBN Prefix

          This is the Official U.S. Government edition of this publication 
              and is herein identified to certify its authenticity. Use of 
              the 0-16 ISBN prefix is for U.S. Government Printing Office 
              Official Editions only. The Superintendent of Documents of the 
              U.S. Government Printing Office requests that any reprinted 
              edition clearly be labeled as a copy of the authentic work 
              with a new ISBN.

              
              
          U . S . G O V E R N M E N T P R I N T I N G O F F I C E

          ------------------------------------------------------------------

          U.S. Superintendent of Documents  Washington, DC 
              20402-0001

          http://bookstore.gpo.gov

          Phone: toll-free (866) 512-1800; DC area (202) 512-1800

[[Page iii]]




                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 40:
          Chapter I--Environmental Protection Agency                 3
  Finding Aids:
      Table of CFR Titles and Chapters........................     605
      Alphabetical List of Agencies Appearing in the CFR......     625
      List of CFR Sections Affected...........................     635

[[Page iv]]





                     ----------------------------

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 40 CFR 50.1 refers 
                       to title 40, part 50, 
                       section 1.

                     ----------------------------

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, July 1, 2009), consult the ``List of CFR 
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative 
List of Parts Affected,'' which appears in the Reader Aids section of 
the daily Federal Register. These two lists will identify the Federal 
Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

    Each volume of the Code contains amendments published in the Federal 
Register since the last revision of that volume of the Code. Source 
citations for the regulations are referred to by volume number and page 
number of the Federal Register and date of publication. Publication 
dates and effective dates are usually not the same and care must be 
exercised by the user in determining the actual effective date. In 
instances where the effective date is beyond the cut-off date for the 
Code a note has been inserted to reflect the future effective date. In 
those instances where a regulation published in the Federal Register 
states a date certain for expiration, an appropriate note will be 
inserted following the text.

OMB CONTROL NUMBERS

    The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires 
Federal agencies to display an OMB control number with their information 
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
amendments to existing regulations in the CFR. These OMB numbers are 
placed as close as possible to the applicable recordkeeping or reporting 
requirements.

OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
the cover of each volume are not carried. Code users may find the text 
of provisions in effect on a given date in the past by using the 
appropriate numerical list of sections affected. For the period before 
January 1, 2001, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, 1973-1985, or 1986-2000, published in eleven separate 
volumes. For the period beginning January 1, 2001, a ``List of CFR 
Sections Affected'' is published at the end of each CFR volume.

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
requirement to publish regulations in the Federal Register by referring 
to materials already published elsewhere. For an incorporation to be 
valid, the Director of the Federal Register must approve it. The legal 
effect of incorporation by reference is that the material is treated as 
if it were published in full in the Federal Register (5 U.S.C. 552(a)). 
This material, like any other properly issued regulation, has the force 
of law.
    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
approval is based are:
    (a) The incorporation will substantially reduce the volume of 
material published in the Federal Register.
    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed as 
an approved incorporation by reference, please contact the agency that 
issued the regulation containing that incorporation. If, after 
contacting the agency, you find the material is not available, please 
notify the Director of the Federal Register, National Archives and 
Records Administration, Washington DC 20408, or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

    A subject index to the Code of Federal Regulations is contained in a 
separate volume, revised annually as of January 1, entitled CFR Index 
and Finding Aids. This volume contains the Parallel Table of Authorities 
and Rules. A list of CFR titles, chapters, subchapters, and parts and an 
alphabetical list of agencies publishing in the CFR are also included in 
this volume.
    An index to the text of ``Title 3--The President'' is carried within 
that volume.
    The Federal Register Index is issued monthly in cumulative form. 
This index is based on a consolidation of the ``Contents'' entries in 
the daily Federal Register.
    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.




[[Page vii]]



REPUBLICATION OF MATERIAL

    There are no restrictions on the republication of material appearing 
in the Code of Federal Regulations.

INQUIRIES

    For a legal interpretation or explanation of any regulation in this 
volume, contact the issuing agency. The issuing agency's name appears at 
the top of odd-numbered pages.
    For inquiries concerning CFR reference assistance, call 202-741-6000 
or write to the Director, Office of the Federal Register, National 
Archives and Records Administration, Washington, DC 20408 or e-mail 
fedreg.info@nara.gov.

SALES

    The Government Printing Office (GPO) processes all sales and 
distribution of the CFR. For payment by credit card, call toll-free, 
866-512-1800, or DC area, 202-512-1800, M-F 8 a.m. to 4 p.m. e.s.t. or 
fax your order to 202-512-2250, 24 hours a day. For payment by check, 
write to: US Government Printing Office - New Orders, P.O. Box 979050, 
St. Louis, MO 63197-9000. For GPO Customer Service call 202-512-1803.

ELECTRONIC SERVICES

    The full text of the Code of Federal Regulations, the LSA (List of 
CFR Sections Affected), The United States Government Manual, the Federal 
Register, Public Laws, Public Papers, Daily Compilation of Presidential 
Documents and the Privacy Act Compilation are available in electronic 
format via Federalregister.gov. For more information, contact Electronic 
Information Dissemination Services, U.S. Government Printing Office. 
Phone 202-512-1530, or 888-293-6498 (toll-free). E-mail, 
gpoaccess@gpo.gov.
    The Office of the Federal Register also offers a free service on the 
National Archives and Records Administration's (NARA) World Wide Web 
site for public law numbers, Federal Register finding aids, and related 
information. Connect to NARA's web site at www.archives.gov/federal-
register. The NARA site also contains links to GPO Access.

    Raymond A. Mosley,
    Director,
    Office of the Federal Register.
    July 1, 2009.







[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of thirty-two 
volumes. The parts in these volumes are arranged in the following order: 
parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-end 
of part 52), parts 53-59, part 60 (60.1-end of part 60, sections), part 
60 (Appendices), parts 61-62, part 63 (63.1-63.599), part 63 (63.600-
63.1199), part 63 (63.1200-63.1439), part 63 (63.1440-63.6175), part 63 
(63.6580-63.8830), part 63 (63.8980-end of part 63) parts 64-71, parts 
72-80, parts 81-84, part 85-Sec.  86.599-99, part 86 (86.600-1-end of 
part 86), parts 87-99, parts 100-135, parts 136-149, parts 150-189, 
parts 190-259, parts 260-265, parts 266-299, parts 300-399, parts 400-
424, parts 425-699, parts 700-789, parts 790-999, and part 1000 to end. 
The contents of these volumes represent all current regulations codified 
under this title of the CFR as of July 1, 2009.

    Chapter I--Environmental Protection Agency appears in all thirty-two 
volumes. Regulations issued by the Council on Environmental Quality, 
including an Index to Parts 1500 through 1508, appear in the volume 
containing part 1000 to end. The OMB control numbers for title 40 appear 
in Sec.  9.1 of this chapter.

    For this volume, Michele Bugenhagen was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.


[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT




                   (This book contains parts 50 to 51)

  --------------------------------------------------------------------
                                                                    Part

chapter i--Environmental Protection Agency (Continued)......          50

[[Page 3]]



         CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)




  --------------------------------------------------------------------

                       SUBCHAPTER C--AIR PROGRAMS
Part                                                                Page
50              National primary and secondary ambient air 
                    quality standards.......................           5
51              Requirements for preparation, adoption, and 
                    submittal of implementation plans.......         140

[[Page 5]]



                        SUBCHAPTER C_AIR PROGRAMS





PART 50_NATIONAL PRIMARY AND SECONDARY AMBIENT AIR QUALITY 
STANDARDS--Table of Contents




Sec.
50.1 Definitions.
50.2 Scope.
50.3 Reference conditions.
50.4 National primary ambient air quality standards for sulfur oxides 
          (sulfur dioxide).
50.5 National secondary ambient air quality standard for sulfur oxides 
          (sulfur dioxide).
50.6 National primary and secondary ambient air quality standards for 
          PM10.
50.7 National primary and secondary ambient air quality standards for 
          PM2.5.
50.8 National primary ambient air quality standards for carbon monoxide.
50.9 National 1-hour primary and secondary ambient air quality standards 
          for ozone.
50.10 National 8-hour primary and secondary ambient air quality 
          standards for ozone.
50.11 National primary and secondary ambient air quality standards for 
          nitrogen dioxide.
50.12 National primary and secondary ambient air quality standards for 
          lead.
50.13 National primary and secondary ambient air quality standards for 
          PM2.5.
50.14 Treatment of air quality monitoring data influenced by exceptional 
          events.
50.15 National primary and secondary ambient air quality standards for 
          ozone.
50.16 National primary and secondary ambient air quality standards for 
          lead.

Appendix A to Part 50--Reference Method for the Determination of Sulfur 
          Dioxide in the Atmosphere (Pararosaniline Method)
Appendix B to Part 50--Reference Method for the Determination of 
          Suspended Particulate Matter in the Atmosphere (High-Volume 
          Method)
Appendix C to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Carbon Monoxide in the Atmosphere (Non-
          Dispersive Infrared Photometry)
Appendix D to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Ozone in the Atmosphere
Appendix E to Part 50 [Reserved]
Appendix F to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Nitrogen Dioxide in the Atmosphere (Gas 
          Phase Chemiluminescence)
Appendix G to Part 50--Reference Method for the Determination of Lead in 
          Suspended Particulate Matter Collected From Ambient Air
Appendix H to Part 50--Interpretation of the 1-Hour Primary and 
          Secondary National Ambient Air Quality Standards for Ozone
Appendix I to Part 50--Interpretation of the 8-Hour Primary and 
          Secondary National Ambient Air Quality Standards for Ozone
Appendix J to Part 50--Reference Method for the Determination of 
          Particulate Matter as PM10 in the Atmosphere
Appendix K to Part 50--Interpretation of the National Ambient Air 
          Quality Standards for Particulate Matter
Appendix L to Part 50--Reference Method for the Determination of Fine 
          Particulate Matter as PM2.5 in the Atmosphere
Appendix M to Part 50 [Reserved]
Appendix N to Part 50--Interpretation of the National Ambient Air 
          Quality Standards for Particulate Matter
Appendix O to Part 50--Reference Method for the Determination of Coarse 
          Particulate Matter as PM10-2.5 in the Atmosphere
Appendix P to Part 50--Interpretation of the Primary and Secondary 
          National Ambient Air Quality Standards for Ozone
Appendix Q to Part 50--Reference Method for the Determination of Lead in 
          Particulate Matter as PM10 Collected From Ambient Air
Appendix R to Part 50--Interpretation of the National Ambient Air 
          Quality Standards for Lead

    Authority: 42 U.S.C. 7401, et seq.

    Source: 36 FR 22384, Nov. 25, 1971, unless otherwise noted.



Sec. 50.1  Definitions.

    (a) As used in this part, all terms not defined herein shall have 
the meaning given them by the Act.
    (b) Act means the Clean Air Act, as amended (42 U.S.C. 1857-18571, 
as amended by Pub. L. 91-604).
    (c) Agency means the Environmental Protection Agency.
    (d) Administrator means the Administrator of the Environmental 
Protection Agency.
    (e) Ambient air means that portion of the atmosphere, external to 
buildings, to which the general public has access.

[[Page 6]]

    (f) Reference method means a method of sampling and analyzing the 
ambient air for an air pollutant that is specified as a reference method 
in an appendix to this part, or a method that has been designated as a 
reference method in accordance with part 53 of this chapter; it does not 
include a method for which a reference method designation has been 
cancelled in accordance with Sec. 53.11 or Sec. 53.16 of this chapter.
    (g) Equivalent method means a method of sampling and analyzing the 
ambient air for an air pollutant that has been designated as an 
equivalent method in accordance with part 53 of this chapter; it does 
not include a method for which an equivalent method designation has been 
cancelled in accordance with Sec. 53.11 or Sec. 53.16 of this chapter.
    (h) Traceable means that a local standard has been compared and 
certified either directly or via not more than one intermediate 
standard, to a primary standard such as a National Bureau of Standards 
Standard Reference Material (NBS SRM), or a USEPA/NBS-approved Certified 
Reference Material (CRM).
    (i) Indian country is as defined in 18 U.S.C. 1151.
    (j) Exceptional event means an event that affects air quality, is 
not reasonably controllable or preventable, is an event caused by human 
activity that is unlikely to recur at a particular location or a natural 
event, and is determined by the Administrator in accordance with 40 CFR 
50.14 to be an exceptional event. It does not include stagnation of air 
masses or meteorological inversions, a meteorological event involving 
high temperatures or lack of precipitation, or air pollution relating to 
source noncompliance.
    (k) Natural event means an event in which human activity plays 
little or no direct causal role.
    (l) Exceedance with respect to a national ambient air quality 
standard means one occurrence of a measured or modeled concentration 
that exceeds the specified concentration level of such standard for the 
averaging period specified by the standard.

[36 FR 22384, Nov. 25, 1971, as amended at 41 FR 11253, Mar. 17, 1976; 
48 FR 2529, Jan. 20, 1983; 63 FR 7274, Feb. 12, 1998; 72 FR 13580, Mar. 
22, 2007]



Sec. 50.2  Scope.

    (a) National primary and secondary ambient air quality standards 
under section 109 of the Act are set forth in this part.
    (b) National primary ambient air quality standards define levels of 
air quality which the Administrator judges are necessary, with an 
adequate margin of safety, to protect the public health. National 
secondary ambient air quality standards define levels of air quality 
which the Administrator judges necessary to protect the public welfare 
from any known or anticipated adverse effects of a pollutant. Such 
standards are subject to revision, and additional primary and secondary 
standards may be promulgated as the Administrator deems necessary to 
protect the public health and welfare.
    (c) The promulgation of national primary and secondary ambient air 
quality standards shall not be considered in any manner to allow 
significant deterioration of existing air quality in any portion of any 
State or Indian country.
    (d) The proposal, promulgation, or revision of national primary and 
secondary ambient air quality standards shall not prohibit any State or 
Indian country from establishing ambient air quality standards for that 
State or area under a tribal CAA program or any portion thereof which 
are more stringent than the national standards.

[36 FR 22384, Nov. 25, 1971, as amended at 63 FR 7274, Feb. 12, 1998]



Sec. 50.3  Reference conditions.

    All measurements of air quality that are expressed as mass per unit 
volume (e.g., micrograms per cubic meter) other than for particulate 
matter (PM2.5) standards contained in Sec. Sec. 50.7 and 
50.13 and lead standards contained in Sec. 50.16 shall be corrected to 
a reference temperature of 25 (deg) C and a reference pressure of 760 
millimeters of mercury (1,013.2 millibars). Measurements of 
PM2.5 for purposes of comparison to the standards contained 
in Sec. Sec. 50.7 and 50.13 and of lead for purposes of comparison to 
the standards contained in Sec. 50.16 shall be reported based on actual 
ambient air volume measured at the actual ambient temperature and

[[Page 7]]

pressure at the monitoring site during the measurement period.

[73 FR 67051, Nov. 12, 2008]



Sec. 50.4  National primary ambient air quality standards for sulfur
oxides (sulfur dioxide).

    (a) The level of the annual standard is 0.030 parts per million 
(ppm), not to be exceeded in a calendar year. The annual arithmetic mean 
shall be rounded to three decimal places (fractional parts equal to or 
greater than 0.0005 ppm shall be rounded up).
    (b) The level of the 24-hour standard is 0.14 parts per million 
(ppm), not to be exceeded more than once per calendar year. The 24-hour 
averages shall be determined from successive nonoverlapping 24-hour 
blocks starting at midnight each calendar day and shall be rounded to 
two decimal places (fractional parts equal to or greater than 0.005 ppm 
shall be rounded up).
    (c) Sulfur oxides shall be measured in the ambient air as sulfur 
dioxide by the reference method described in appendix A to this part or 
by an equivalent method designated in accordance with part 53 of this 
chapter.
    (d) To demonstrate attainment, the annual arithmetic mean and the 
second-highest 24-hour averages must be based upon hourly data that are 
at least 75 percent complete in each calendar quarter. A 24-hour block 
average shall be considered valid if at least 75 percent of the hourly 
averages for the 24-hour period are available. In the event that only 
18, 19, 20, 21, 22, or 23 hourly averages are available, the 24-hour 
block average shall be computed as the sum of the available hourly 
averages using 18, 19, etc. as the divisor. If fewer than 18 hourly 
averages are available, but the 24-hour average would exceed the level 
of the standard when zeros are substituted for the missing values, 
subject to the rounding rule of paragraph (b) of this section, then this 
shall be considered a valid 24-hour average. In this case, the 24-hour 
block average shall be computed as the sum of the available hourly 
averages divided by 24.

[61 FR 25579, May 22, 1996]



Sec. 50.5  National secondary ambient air quality standard for sulfur
oxides (sulfur dioxide).

    (a) The level of the 3-hour standard is 0.5 parts per million (ppm), 
not to be exceeded more than once per calendar year. The 3-hour averages 
shall be determined from successive nonoverlapping 3-hour blocks 
starting at midnight each calendar day and shall be rounded to 1 decimal 
place (fractional parts equal to or greater than 0.05 ppm shall be 
rounded up).
    (b) Sulfur oxides shall be measured in the ambient air as sulfur 
dioxide by the reference method described in appendix A of this part or 
by an equivalent method designated in accordance with part 53 of this 
chapter.
    (c) To demonstrate attainment, the second-highest 3-hour average 
must be based upon hourly data that are at least 75 percent complete in 
each calendar quarter. A 3-hour block average shall be considered valid 
only if all three hourly averages for the 3-hour period are available. 
If only one or two hourly averages are available, but the 3-hour average 
would exceed the level of the standard when zeros are substituted for 
the missing values, subject to the rounding rule of paragraph (a) of 
this section, then this shall be considered a valid 3-hour average. In 
all cases, the 3-hour block average shall be computed as the sum of the 
hourly averages divided by 3.

[61 FR 25580, May 22, 1996]



Sec. 50.6  National primary and secondary ambient air quality standards
for PM[bdi1][bdi0].

    (a) The level of the national primary and secondary 24-hour ambient 
air quality standards for particulate matter is 150 micrograms per cubic 
meter ([micro]g/m\3\), 24-hour average concentration. The standards are 
attained when the expected number of days per calendar year with a 24-
hour average concentration above 150 [micro]g/m\3\, as determined in 
accordance with appendix K to this part, is equal to or less than one.
    (b) [Reserved]
    (c) For the purpose of determining attainment of the primary and 
secondary standards, particulate matter shall be measured in the ambient 
air as PM10 (particles with an aerodynamic

[[Page 8]]

diameter less than or equal to a nominal 10 micrometers) by:
    (1) A reference method based on appendix J and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.

[52 FR 24663, July 1, 1987, as amended at 62 FR 38711, July 18, 1997; 65 
FR 80779, Dec. 22, 2000; 71 FR 61224, Oct. 17, 2006]



Sec. 50.7  National primary and secondary ambient air quality standards
for PM[bdi2].[bdi5].

    (a) The national primary and secondary ambient air quality standards 
for particulate matter are 15.0 micrograms per cubic meter ([micro]g/
m\3\) annual arithmetic mean concentration, and 65 [micro]g/m\3\ 24-hour 
average concentration measured in the ambient air as PM2.5 
(particles with an aerodynamic diameter less than or equal to a nominal 
2.5 micrometers) by either:
    (1) A reference method based on appendix L of this part and 
designated in accordance with part 53 of this chapter; or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (b) The annual primary and secondary PM2.5 standards are 
met when the annual arithmetic mean concentration, as determined in 
accordance with appendix N of this part, is less than or equal to 15.0 
micrograms per cubic meter.
    (c) The 24-hour primary and secondary PM2.5 standards are 
met when the 98th percentile 24-hour concentration, as 
determined in accordance with appendix N of this part, is less than or 
equal to 65 micrograms per cubic meter.

[62 FR 38711, July 18, 1997, as amended at 69 FR 45595, July 30, 2004]



Sec. 50.8  National primary ambient air quality standards for carbon
monoxide.

    (a) The national primary ambient air quality standards for carbon 
monoxide are:
    (1) 9 parts per million (10 milligrams per cubic meter) for an 8-
hour average concentration not to be exceeded more than once per year 
and
    (2) 35 parts per million (40 milligrams per cubic meter) for a 1-
hour average concentration not to be exceeded more than once per year.
    (b) The levels of carbon monoxide in the ambient air shall be 
measured by:
    (1) A reference method based on appendix C and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (c) An 8-hour average shall be considered valid if at least 75 
percent of the hourly average for the 8-hour period are available. In 
the event that only six (or seven) hourly averages are available, the 8-
hour average shall be computed on the basis of the hours available using 
six (or seven) as the divisor.
    (d) When summarizing data for comparision with the standards, 
averages shall be stated to one decimal place. Comparison of the data 
with the levels of the standards in parts per million shall be made in 
terms of integers with fractional parts of 0.5 or greater rounding up.

[50 FR 37501, Sept. 13, 1985]



Sec. 50.9  National 1-hour primary and secondary ambient air quality 
standards for ozone.

    (a) The level of the national 1-hour primary and secondary ambient 
air quality standards for ozone measured by a reference method based on 
appendix D to this part and designated in accordance with part 53 of 
this chapter, is 0.12 parts per million (235 [micro]g/m\3\). The 
standard is attained when the expected number of days per calendar year 
with maximum hourly average concentrations above 0.12 parts per million 
(235 [micro]g/m\3\) is equal to or less than 1, as determined by 
appendix H to this part.
    (b) The 1-hour standards set forth in this section will remain 
applicable to all areas notwithstanding the promulgation of 8-hour ozone 
standards under Sec. 50.10. The 1-hour NAAQS set forth in paragraph (a) 
of this section will no longer apply to an area one year after the 
effective date of the designation of that area for the 8-hour ozone 
NAAQS pursuant to section 107 of the Clean Air

[[Page 9]]

Act. Area designations and classifications with respect to the 1-hour 
standards are codified in 40 CFR part 81.
    (c) EPA's authority under paragraph (b) of this section to determine 
that the 1-hour standard no longer applies to an area based on a 
determination that the area has attained the 1-hour standard is stayed 
until such time as EPA issues a final rule revising or reinstating such 
authority and considers and addresses in such rulemaking any comments 
concerning (1) which, if any, implementation activities for a revised 
ozone standard (including but not limited to designation and 
classification of areas) would need to occur before EPA would determine 
that the 1-hour ozone standard no longer applies to an area, and (2) the 
effect of revising the ozone NAAQS on the existing 1-hour ozone 
designations.

[62 FR 38894, July 18, 1997, as amended at 65 FR 45200, July 20, 2000; 
68 FR 38163, June 26, 2003, 69 FR 23996, Apr. 30, 2004]



Sec. 50.10  National 8-hour primary and secondary ambient air quality
standards for ozone.

    (a) The level of the national 8-hour primary and secondary ambient 
air quality standards for ozone, measured by a reference method based on 
appendix D to this part and designated in accordance with part 53 of 
this chapter, is 0.08 parts per million (ppm), daily maximum 8-hour 
average.
    (b) The 8-hour primary and secondary ozone ambient air quality 
standards are met at an ambient air quality monitoring site when the 
average of the annual fourth-highest daily maximum 8-hour average ozone 
concentration is less than or equal to 0.08 ppm, as determined in 
accordance with appendix I to this part.

[62 FR 38894, July 18, 1997]



Sec. 50.11  National primary and secondary ambient air quality standards
for nitrogen dioxide.

    (a) The level of the national primary ambient air quality standard 
for nitrogen dioxide is 0.053 parts per million (100 micrograms per 
cubic meter), annual arithmetic mean concentration.
    (b) The level of national secondary ambient air quality standard for 
nitrogen dioxide is 0.053 parts per million (100 micrograms per cubic 
meter), annual arithmetic mean concentration.
    (c) The levels of the standards shall be measured by:
    (1) A reference method based on appendix F and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (d) The standards are attained when the annual arithmetic mean 
concentration in a calendar year is less than or equal to 0.053 ppm, 
rounded to three decimal places (fractional parts equal to or greater 
than 0.0005 ppm must be rounded up). To demonstrate attainment, an 
annual mean must be based upon hourly data that are at least 75 percent 
complete or upon data derived from manual methods that are at least 75 
percent complete for the scheduled sampling days in each calendar 
quarter.

[50 FR 25544, June 19, 1985]



Sec. 50.12  National primary and secondary ambient air quality standards
for lead.

    (a) National primary and secondary ambient air quality standards for 
lead and its compounds, measured as elemental lead by a reference method 
based on appendix G to this part, or by an equivalent method, are: 1.5 
micrograms per cubic meter, maximum arithmetic mean averaged over a 
calendar quarter.
    (b) The standards set forth in this section will remain applicable 
to all areas notwithstanding the promulgation of lead national ambient 
air quality standards (NAAQS) in Sec. 50.16. The lead NAAQS set forth 
in this section will no longer apply to an area one year after the 
effective date of the designation of that area, pursuant to section 107 
of the Clean Air Act, for the lead NAAQS set forth in Sec. 50.16; 
except that for areas designated nonattainment for the lead NAAQS set 
forth in this section as of the effective date of Sec. 50.16, the lead 
NAAQS set forth in this section will apply until that area submits, 
pursuant to section 191 of the Clean Air Act, and EPA approves, an

[[Page 10]]

implementation plan providing for attainment and/or maintenance of the 
lead NAAQS set forth in Sec. 50.16.

(Secs. 109, 301(a) Clean Air Act as amended (42 U.S.C. 7409, 7601(a)))

[43 FR 46258, Oct. 5, 1978, as amended at 73 FR 67051, Nov. 12, 2008]



Sec. 50.13  National primary and secondary ambient air quality standards
for PM2.5.

    (a) The national primary and secondary ambient air quality standards 
for particulate matter are 15.0 micrograms per cubic meter ([micro]g/
m\3\) annual arithmetic mean concentration, and 35 [micro]g/m\3\ 24-hour 
average concentration measured in the ambient air as PM2.5 
(particles with an aerodynamic diameter less than or equal to a nominal 
2.5 micrometers) by either:
    (1) A reference method based on appendix L of this part and 
designated in accordance with part 53 of this chapter; or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (b) The annual primary and secondary PM2.5 standards are 
met when the annual arithmetic mean concentration, as determined in 
accordance with appendix N of this part, is less than or equal to 15.0 
[micro]g/m\3\.
    (c) The 24-hour primary and secondary PM2.5 standards are 
met when the 98th percentile 24-hour concentration, as determined in 
accordance with appendix N of this part, is less than or equal to 35 
[micro]g/m\3\.

[71 FR 61224, Oct. 17, 2006]



Sec. 50.14  Treatment of air quality monitoring data influenced by 
exceptional events.

    (a) Requirements. (1) A State may request EPA to exclude data 
showing exceedances or violations of the national ambient air quality 
standard that are directly due to an exceptional event from use in 
determinations by demonstrating to EPA's satisfaction that such event 
caused a specific air pollution concentration at a particular air 
quality monitoring location.
    (2) Demonstration to justify data exclusion may include any reliable 
and accurate data, but must demonstrate a clear causal relationship 
between the measured exceedance or violation of such standard and the 
event in accordance with paragraph (c)(3)(iv) of this section.
    (b) Determinations by EPA. (1) EPA shall exclude data from use in 
determinations of exceedances and NAAQS violations where a State 
demonstrates to EPA's satisfaction that an exceptional event caused a 
specific air pollution concentration in excess of one or more national 
ambient air quality standards at a particular air quality monitoring 
location and otherwise satisfies the requirements of this section.
    (2) EPA shall exclude data from use in determinations of exceedances 
and NAAQS violations where a State demonstrates to EPA's satisfaction 
that emissions from fireworks displays caused a specific air pollution 
concentration in excess of one or more national ambient air quality 
standards at a particular air quality monitoring location and otherwise 
satisfies the requirements of this section. Such data will be treated in 
the same manner as exceptional events under this rule, provided a State 
demonstrates that such use of fireworks is significantly integral to 
traditional national, ethnic, or other cultural events including, but 
not limited to July Fourth celebrations which satisfy the requirements 
of this section.
    (3) EPA shall exclude data from use in determinations of exceedances 
and NAAQS violations, where a State demonstrates to EPA's satisfaction 
that emissions from prescribed fires caused a specific air pollution 
concentration in excess of one or more national ambient air quality 
standards at a particular air quality monitoring location and otherwise 
satisfies the requirements of this section provided that such emissions 
are from prescribed fires that EPA determines meets the definition in 
Sec. 50.1(j), and provided that the State has certified to EPA that it 
has adopted and is implementing a Smoke Management Program or the State 
has ensured that the burner employed basic smoke management practices. 
If an exceptional event occurs using the basic smoke management

[[Page 11]]

practices approach, the State must undertake a review of its approach to 
ensure public health is being protected and must include consideration 
of development of a SMP.
    (4) [Reserved]
    (c) Schedules and Procedures. (1) Public notification.
    (i) All States and, where applicable, their political subdivisions 
must notify the public promptly whenever an event occurs or is 
reasonably anticipated to occur which may result in the exceedance of an 
applicable air quality standard.
    (ii) [Reserved]
    (2) Flagging of data.
    (i) A State shall notify EPA of its intent to exclude one or more 
measured exceedances of an applicable ambient air quality standard as 
being due to an exceptional event by placing a flag in the appropriate 
field for the data record of concern which has been submitted to the AQS 
database.
    (ii) Flags placed on data in accordance with this section shall be 
deemed informational only, and the data shall not be excluded from 
determinations with respect to exceedances or violations of the national 
ambient air quality standards unless and until, following the State's 
submittal of its demonstration pursuant to paragraph (c)(3) of this 
section and EPA review, EPA notifies the State of its concurrence by 
placing a concurrence flag in the appropriate field for the data record 
in the AQS database.
    (iii) Flags placed on data as being due to an exceptional event 
together with an initial description of the event shall be submitted to 
EPA not later than July 1st of the calendar year following the year in 
which the flagged measurement occurred, except as allowed under 
paragraph (c)(2)(iv) or (c)(2)(v) of this section.
    (iv) For PM2.5 data collected during calendar years 2004-
2006, that the State identifies as resulting from an exceptional event, 
the State must notify EPA of the flag and submit an initial description 
of the event no later than October 1, 2007. EPA may grant an extension, 
if a State requests an extension, and permit the State to submit the 
notification of the flag and initial description by no later than 
December 1, 2007.
    (v) For lead (Pb) data collected during calendar years 2006-2008, 
that the State identifies as resulting from an exceptional event, the 
State must notify EPA of the flag and submit an initial description of 
the event no later than July 1, 2009. For Pb data collected during 
calendar year 2009, that the State identifies as resulting from an 
exceptional event, the State must notify EPA of the flag and submit an 
initial description of the event no later than July 1, 2010. For Pb data 
collected during calendar year 2010, that the State identifies as 
resulting from an exceptional event, the State must notify EPA of the 
flag and submit an initial description of the event no later than May 1, 
2011.
    (vi) When EPA sets a NAAQS for a new pollutant or revises the NAAQS 
for an existing pollutant, it may revise or set a new schedule for 
flagging exceptional event data, providing initial data descriptions and 
providing detailed data documentation in AQS for the initial 
designations of areas for those NAAQS: Table 1 provides the schedule for 
submission of flags with initial descriptions in AQS and detailed 
documentation and the schedule shall apply for those data which will or 
may influence the initial designation of areas for those NAAQS. EPA 
anticipates revising Table 1 as necessary to accommodate revised data 
submission schedules for new or revised NAAQS.

      Table 1--Schedule for Exceptional Event Flagging and Documentation Submission for Data To Be Used in
                                 Designations Decisions for New or Revised NAAQS
----------------------------------------------------------------------------------------------------------------
                                           Air quality data         Event flagging &
 NAAQS pollutant/  standard/(level)/   collected for  calendar    initial  description    Detailed documentation
          promulgation date                      year                   deadline           submission deadline
----------------------------------------------------------------------------------------------------------------
PM2.5/24-Hr Standard (35 [micro]g/     2004-2006..............  October 1, 2007\a\.....  April 15, 2008.\a\
 m\3\) Promulgated October 17, 2006.

[[Page 12]]

 
Ozone/8-Hr Standard (0.075 ppm)        2005-2007..............  June 18, 2009\b\.......  June 18, 2009.\b\
 Promulgated March 12, 2008.
                                       2008...................  June 18, 2009\b\.......  June 18, 2009.\b\
                                       2009...................  60 Days after the end    60 Days after the end
                                                                 of the calendar          of the calendar
                                                                 quarter in which the     quarter in which the
                                                                 event occurred or        event occurred or
                                                                 February 5, 2010,        February 5, 2010,
                                                                 whichever date occurs    whichever date occurs
                                                                 first.\b\.               first.\b\
----------------------------------------------------------------------------------------------------------------
\a\ These dates are unchanged from those published in the original rulemaking, and are shown in this table for
  informational purposes.
\b\ Indicates change from general schedule in 40 CFR 50.14.
Note: EPA notes that the table of revised deadlines only applies to data EPA will use to establish the final
  initial designations for new or revised NAAQS. The general schedule applies for all other purposes, most
  notably, for data used by EPA for redesignations to attainment.

    (3) Submission of demonstrations.
    (i) A State that has flagged data as being due to an exceptional 
event and is requesting exclusion of the affected measurement data 
shall, after notice and opportunity for public comment, submit a 
demonstration to justify data exclusion to EPA not later than the lesser 
of, 3 years following the end of the calendar quarter in which the 
flagged concentration was recorded or, 12 months prior to the date that 
a regulatory decision must be made by EPA. A State must submit the 
public comments it received along with its demonstration to EPA.
    (ii) A State that flags data collected during calendar years 2004-
2006, pursuant to paragraph (c)(2)(iv) of this section, must adopt the 
procedures and requirements specified in paragraph (c)(3)(i) of this 
section and must include a demonstration to justify the exclusion of the 
data not later than the submittal of the Governor's recommendation 
letter on nonattainment areas.
    (iii) A State that flags Pb data collected during calendar years 
2006-2009, pursuant to paragraph (c)(2)(v) of this section shall, after 
notice and opportunity for public comment, submit to EPA a demonstration 
to justify exclusion of the data not later than October 15, 2010. A 
State that flags Pb data collected during calendar year 2010 shall, 
after notice and opportunity for public comment, submit to EPA a 
demonstration to justify the exclusion of the data not later than May 1, 
2011. A state must submit the public comments it received along with its 
demonstration to EPA.
    (iv) The demonstration to justify data exclusion shall provide 
evidence that:
    (A) The event satisfies the criteria set forth in 40 CFR 50.1(j);
    (B) There is a clear causal relationship between the measurement 
under consideration and the event that is claimed to have affected the 
air quality in the area;
    (C) The event is associated with a measured concentration in excess 
of normal historical fluctuations, including background; and
    (D) There would have been no exceedance or violation but for the 
event.
    (v) With the submission of the demonstration, the State must 
document that the public comment process was followed.

[72 FR 13580, Mar. 22, 2007; 72 FR 28612, May 22, 2007; 73 FR 67051, 
Nov. 12, 2008; 74 FR 70598, Nov. 21, 2008; 74 FR 23312, May 19, 2009]



Sec. 50.15  National primary and secondary ambient air quality standards
for ozone.

    (a) The level of the national 8-hour primary and secondary ambient 
air quality standards for ozone (O3) is 0.075 parts per million (ppm), 
daily maximum 8-hour average, measured by a reference method based on 
appendix D to this part and designated in accordance with part 53 of 
this chapter or an equivalent method designated in accordance with part 
53 of this chapter.

[[Page 13]]

    (b) The 8-hour primary and secondary O3 ambient air quality 
standards are met at an ambient air quality monitoring site when the 3-
year average of the annual fourth-highest daily maximum 8-hour average 
O3 concentration is less than or equal to 0.075 ppm, as determined in 
accordance with appendix P to this part.

[73 FR 16511, Mar. 27, 2008]



Sec. 50.16  National primary and secondary ambient air quality standards
for lead.

    (a) The national primary and secondary ambient air quality standards 
for lead (Pb) and its compounds are 0.15 micrograms per cubic meter, 
arithmetic mean concentration over a 3-month period, measured in the 
ambient air as Pb either by:
    (1) A reference method based on Appendix G of this part and 
designated in accordance with part 53 of this chapter or;
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (b) The national primary and secondary ambient air quality standards 
for Pb are met when the maximum arithmetic 3-month mean concentration 
for a 3-year period, as determined in accordance with Appendix R of this 
part, is less than or equal to 0.15 micrograms per cubic meter.

[73 FR 67052, Nov. 12, 2008]



 Sec. Appendix A to Part 50--Reference Method for the Determination of 
        Sulfur Dioxide in the Atmosphere (Pararosaniline Method)

    1.0 Applicability.
    1.1 This method provides a measurement of the concentration of 
sulfur dioxide (SO2) in ambient air for determining 
compliance with the primary and secondary national ambient air quality 
standards for sulfur oxides (sulfur dioxide) as specified in Sec. 50.4 
and Sec. 50.5 of this chapter. The method is applicable to the 
measurement of ambient SO2 concentrations using sampling 
periods ranging from 30 minutes to 24 hours. Additional quality 
assurance procedures and guidance are provided in part 58, appendixes A 
and B, of this chapter and in references 1 and 2.
    2.0 Principle.
    2.1 A measured volume of air is bubbled through a solution of 0.04 M 
potassium tetrachloromercurate (TCM). The SO2 present in the 
air stream reacts with the TCM solution to form a stable 
monochlorosulfonatomercurate(3) complex. Once formed, this complex 
resists air oxidation(4, 5) and is stable in the presence of strong 
oxidants such as ozone and oxides of nitrogen. During subsequent 
analysis, the complex is reacted with acid-bleached pararosaniline dye 
and formaldehyde to form an intensely colored pararosaniline methyl 
sulfonic acid.(6) The optical density of this species is determined 
spectrophotometrically at 548 nm and is directly related to the amount 
of SO2 collected. The total volume of air sampled, corrected 
to EPA reference conditions (25 [deg]C, 760 mm Hg [101 kPa]), is 
determined from the measured flow rate and the sampling time. The 
concentration of SO2 in the ambient air is computed and 
expressed in micrograms per standard cubic meter ([micro]g/std m\3\).
    3.0 Range.
    3.1 The lower limit of detection of SO2 in 10 mL of TCM 
is 0.75 [micro]g (based on collaborative test results).(7) This 
represents a concentration of 25 [micro]g SO2/m\3\ (0.01 ppm) 
in an air sample of 30 standard liters (short-term sampling) and a 
concentration of 13 [micro]g SO2/m\3\ (0.005 ppm) in an air 
sample of 288 standard liters (long-term sampling). Concentrations less 
than 25 [micro]g SO2/m\3\ can be measured by sampling larger 
volumes of ambient air; however, the collection efficiency falls off 
rapidly at low concentrations.(8, 9) Beer's law is adhered to up to 34 
[micro]g of SO2 in 25 mL of final solution. This upper limit 
of the analysis range represents a concentration of 1,130 [micro]g 
SO2/m\3\ (0.43 ppm) in an air sample of 30 standard liters 
and a concentration of 590 [micro]g SO2/m\3\ (0.23 ppm) in an 
air sample of 288 standard liters. Higher concentrations can be measured 
by collecting a smaller volume of air, by increasing the volume of 
absorbing solution, or by diluting a suitable portion of the collected 
sample with absorbing solution prior to analysis.
    4.0 Interferences.
    4.1 The effects of the principal potential interferences have been 
minimized or eliminated in the following manner: Nitrogen oxides by the 
addition of sulfamic acid,(10, 11) heavy metals by the addition of 
ethylenediamine tetracetic acid disodium salt (EDTA) and phosphoric 
acid,(10, 12) and ozone by time delay.(10) Up to 60 [micro]g Fe (III), 
22 [micro]g V (V), 10 [micro]g Cu (II), 10 [micro]g Mn (II), and 10 
[micro]g Cr (III) in 10 mL absorbing reagent can be tolerated in the 
procedure.(10) No significant interference has been encountered with 2.3 
[micro]g NH3.(13)
    5.0 Precision and Accuracy.
    5.1 The precision of the analysis is 4.6 percent (at the 95 percent 
confidence level) based on the analysis of standard sulfite samples.(10)
    5.2 Collaborative test results (14) based on the analysis of 
synthetic test atmospheres

[[Page 14]]

(SO2 in scrubbed air) using the 24-hour sampling procedure 
and the sulfite-TCM calibration procedure show that:

 The replication error varies linearly with 
concentration from 2.5 [micro]g/m\3\ at 
concentrations of 100 [micro]g/m\3\ to 7 [micro]g/
m\3\ at concentrations of 400 [micro]g/m\3\.
 The day-to-day variability within an individual 
laboratory (repeatability) varies linearly with concentration from 
18.1 [micro]g/m\3\ at levels of 100 [micro]g/m\3\ 
to 50.9 [micro]g/m\3\ at levels of 400 [micro]g/
m\3\.
 The day-to-day variability between two or more 
laboratories (reproducibility) varies linearly with concentration from 
36.9 [micro]g/m\3\ at levels of 100 [micro]g/m\3\ 
to 103.5 [micro] g/m\3\ at levels of 400 [micro]g/
m\3\.
 The method has a concentration-dependent bias, which 
becomes significant at the 95 percent confidence level at the high 
concentration level. Observed values tend to be lower than the expected 
SO2 concentration level.

    6.0 Stability.
    6.1 By sampling in a controlled temperature environment of 
15[deg]10 [deg]C, greater than 98.9 percent of the 
SO2-TCM complex is retained at the completion of sampling. 
(15) If kept at 5 [deg]C following the completion of sampling, the 
collected sample has been found to be stable for up to 30 days.(10) The 
presence of EDTA enhances the stability of SO2 in the TCM 
solution and the rate of decay is independent of the concentration of 
SO2.(16)
    7.0 Apparatus.
    7.1 Sampling.
    7.1.1 Sample probe: A sample probe meeting the requirements of 
section 7 of 40 CFR part 58, appendix E (Teflon [reg] or 
glass with residence time less than 20 sec.) is used to transport 
ambient air to the sampling train location. The end of the probe should 
be designed or oriented to preclude the sampling of precipitation, large 
particles, etc. A suitable probe can be constructed from Teflon 
[reg] tubing connected to an inverted funnel.
    7.1.2 Absorber--short-term sampling: An all glass midget impinger 
having a solution capacity of 30 mL and a stem clearance of 4 1 mm from the bottom of the vessel is used for sampling 
periods of 30 minutes and 1 hour (or any period considerably less than 
24 hours). Such an impinger is shown in Figure 1. These impingers are 
commercially available from distributors such as Ace Glass, 
Incorporated.
    7.1.3 Absorber--24-hour sampling: A polypropylene tube 32 mm in 
diameter and 164 mm long (available from Bel Art Products, Pequammock, 
NJ) is used as the absorber. The cap of the absorber must be a 
polypropylene cap with two ports (rubber stoppers are unacceptable 
because the absorbing reagent can react with the stopper to yield 
erroneously high SO2 concentrations). A glass impinger stem, 
6 mm in diameter and 158 mm long, is inserted into one port of the 
absorber cap. The tip of the stem is tapered to a small diameter orifice 
(0.4 0.1 mm) such that a No. 79 jeweler's drill 
bit will pass through the opening but a No. 78 drill bit will not. 
Clearance from the bottom of the absorber to the tip of the stem must be 
6 2 mm. Glass stems can be fabricated by any 
reputable glass blower or can be obtained from a scientific supply firm. 
Upon receipt, the orifice test should be performed to verify the orifice 
size. The 50 mL volume level should be permanently marked on the 
absorber. The assembled absorber is shown in Figure 2.
    7.1.4 Moisture trap: A moisture trap constructed of a glass trap as 
shown in Figure 1 or a polypropylene tube as shown in Figure 2 is placed 
between the absorber tube and flow control device to prevent entrained 
liquid from reaching the flow control device. The tube is packed with 
indicating silica gel as shown in Figure 2. Glass wool may be 
substituted for silica gel when collecting short-term samples (1 hour or 
less) as shown in Figure 1, or for long term (24 hour) samples if flow 
changes are not routinely encountered.
    7.1.5 Cap seals: The absorber and moisture trap caps must seal 
securely to prevent leaks during use. Heat-shrink material as shown in 
Figure 2 can be used to retain the cap seals if there is any chance of 
the caps coming loose during sampling, shipment, or storage.

[[Page 15]]




[[Page 16]]





[[Page 17]]


    7.1.6 Flow control device: A calibrated rotameter and needle valve 
combination capable of maintaining and measuring air flow to within 
2 percent is suitable for short-term sampling but 
may not be used for long-term sampling. A critical orifice can be used 
for regulating flow rate for both long-term and short-term sampling. A 
22-gauge hypodermic needle 25 mm long may be used as a critical orifice 
to yield a flow rate of approximately 1 L/min for a 30-minute sampling 
period. When sampling for 1 hour, a 23-gauge hypodermic needle 16 mm in 
length will provide a flow rate of approximately 0.5 L/min. Flow control 
for a 24-hour sample may be provided by a 27-gauge hypodermic needle 
critical orifice that is 9.5 mm in length. The flow rate should be in 
the range of 0.18 to 0.22 L/min.
    7.1.7 Flow measurement device: Device calibrated as specified in 
9.4.1 and used to measure sample flow rate at the monitoring site.
    7.1.8 Membrane particle filter: A membrane filter of 0.8 to 2 
[micro]m porosity is used to protect the flow controller from particles 
during long-term sampling. This item is optional for short-term 
sampling.
    7.1.9 Vacuum pump: A vacuum pump equipped with a vacuum gauge and 
capable of maintaining at least 70 kPa (0.7 atm) vacuum differential 
across the flow control device at the specified flow rate is required 
for sampling.
    7.1.10 Temperature control device: The temperature of the absorbing 
solution during sampling must be maintained at 15[deg] 10 [deg]C. As soon as possible following sampling and 
until analysis, the temperature of the collected sample must be 
maintained at 5[deg] 5 [deg]C. Where an extended 
period of time may elapse before the collected sample can be moved to 
the lower storage temperature, a collection temperature near the lower 
limit of the 15 10 [deg]C range should be used to 
minimize losses during this period. Thermoelectric coolers specifically 
designed for this temperature control are available commercially and 
normally operate in the range of 5[deg] to 15 [deg]C. Small 
refrigerators can be modified to provide the required temperature 
control; however, inlet lines must be insulated from the lower 
temperatures to prevent condensation when sampling under humid 
conditions. A small heating pad may be necessary when sampling at low 
temperatures (<7 [deg]C) to prevent the absorbing solution from 
freezing.(17)
    7.1.11 Sampling train container: The absorbing solution must be 
shielded from light during and after sampling. Most commercially 
available sampler trains are enclosed in a light-proof box.
    7.1.12 Timer: A timer is recommended to initiate and to stop 
sampling for the 24-hour period. The timer is not a required piece of 
equipment; however, without the timer a technician would be required to 
start and stop the sampling manually. An elapsed time meter is also 
recommended to determine the duration of the sampling period.
    7.2 Shipping.
    7.2.1 Shipping container: A shipping container that can maintain a 
temperature of 5[deg] 5 [deg]C is used for 
transporting the sample from the collection site to the analytical 
laboratory. Ice coolers or refrigerated shipping containers have been 
found to be satisfactory. The use of eutectic cold packs instead of ice 
will give a more stable temperature control. Such equipment is available 
from Cole-Parmer Company, 7425 North Oak Park Avenue, Chicago, IL 60648.
    7.3 Analysis.
    7.3.1 Spectrophotometer: A spectrophotometer suitable for 
measurement of absorbances at 548 nm with an effective spectral 
bandwidth of less than 15 nm is required for analysis. If the 
spectrophotometer reads out in transmittance, convert to absorbance as 
follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.000

where:

A = absorbance, and
T = transmittance (0<=T<1).

    A standard wavelength filter traceable to the National Bureau of 
Standards is used to verify the wavelength calibration according to the 
procedure enclosed with the filter. The wavelength calibration must be 
verified upon initial receipt of the instrument and after each 160 hours 
of normal use or every 6 months, whichever occurs first.
    7.3.2 Spectrophotometer cells: A set of 1-cm path length cells 
suitable for use in the visible region is used during analysis. If the 
cells are unmatched, a matching correction factor must be determined 
according to Section 10.1.
    7.3.3 Temperature control device: The color development step during 
analysis must be conducted in an environment that is in the range of 
20[deg] to 30 [deg]C and controlled to 1 [deg]C. 
Both calibration and sample analysis must be performed under identical 
conditions (within 1 [deg]C). Adequate temperature control may be 
obtained by means of constant temperature baths, water baths with manual 
temperature control, or temperature controlled rooms.
    7.3.4 Glassware: Class A volumetric glassware of various capacities 
is required for preparing and standardizing reagents and standards and 
for dispensing solutions during analysis. These included pipets, 
volumetric flasks, and burets.
    7.3.5 TCM waste receptacle: A glass waste receptacle is required for 
the storage of spent TCM solution. This vessel should be stoppered and 
stored in a hood at all times.
    8.0 Reagents.
    8.1 Sampling.

[[Page 18]]

    8.1.1 Distilled water: Purity of distilled water must be verified by 
the following procedure:(18)
 Place 0.20 mL of potassium permanganate solution 
(0.316 g/L), 500 mL of distilled water, and 1mL of concentrated sulfuric 
acid in a chemically resistant glass bottle, stopper the bottle, and 
allow to stand.
 If the permanganate color (pink) does not disappear 
completely after a period of 1 hour at room temperature, the water is 
suitable for use.
 If the permanganate color does disappear, the water 
can be purified by redistilling with one crystal each of barium 
hydroxide and potassium permanganate in an all glass still.

    8.1.2 Absorbing reagent (0.04 M potassium tetrachloromercurate 
[TCM]): Dissolve 10.86 g mercuric chloride, 0.066 g EDTA, and 6.0 g 
potassium chloride in distilled water and dilute to volume with 
distilled water in a 1,000-mL volumetric flask. (Caution: Mercuric 
chloride is highly poisonous. If spilled on skin, flush with water 
immediately.) The pH of this reagent should be between 3.0 and 5.0 (10) 
Check the pH of the absorbing solution by using pH indicating paper or a 
pH meter. If the pH of the solution is not between 3.0 and 5.0, dispose 
of the solution according to one of the disposal techniques described in 
Section 13.0. The absorbing reagent is normally stable for 6 months. If 
a precipitate forms, dispose of the reagent according to one of the 
procedures described in Section 13.0.
    8.2 Analysis.
    8.2.1 Sulfamic acid (0.6%): Dissolve 0.6 g sulfamic acid in 100 mL 
distilled water. Perpare fresh daily.
    8.2.2 Formaldehyde (0.2%): Dilute 5 mL formaldehyde solution (36 to 
38 percent) to 1,000 mL with distilled water. Prepare fresh daily.
    8.2.3 Stock iodine solution (0.1 N): Place 12.7 g resublimed iodine 
in a 250-mL beaker and add 40 g potassium iodide and 25 mL water. Stir 
until dissolved, transfer to a 1,000 mL volumetric flask and dilute to 
volume with distilled water.
    8.2.4 Iodine solution (0.01 N): Prepare approximately 0.01 N iodine 
solution by diluting 50 mL of stock iodine solution (Section 8.2.3) to 
500 mL with distilled water.
    8.2.5 Starch indicator solution: Triturate 0.4 g soluble starch and 
0.002 g mercuric iodide (preservative) with enough distilled water to 
form a paste. Add the paste slowly to 200 mL of boiling distilled water 
and continue boiling until clear. Cool and transfer the solution to a 
glass stopperd bottle.
    8.2.6 1 N hydrochloric acid: Slowly and while stirring, add 86 mL of 
concentrated hydrochloric acid to 500 mL of distilled water. Allow to 
cool and dilute to 1,000 mL with distilled water.
    8.2.7 Potassium iodate solution: Accurately weigh to the nearest 0.1 
mg, 1.5 g (record weight) of primary standard grade potassium iodate 
that has been previously dried at 180 [deg]C for at least 3 hours and 
cooled in a dessicator. Dissolve, then dilute to volume in a 500-mL 
volumetric flask with distilled water.
    8.2.8 Stock sodium thiosulfate solution (0.1 N): Prepare a stock 
solution by dissolving 25 g sodium thiosulfate (Na2 
S2 O3/5H2 O) in 1,000 mL freshly 
boiled, cooled, distilled water and adding 0.1 g sodium carbonate to the 
solution. Allow the solution to stand at least 1 day before 
standardizing. To standardize, accurately pipet 50 mL of potassium 
iodate solution (Section 8.2.7) into a 500-mL iodine flask and add 2.0 g 
of potassium iodide and 10 mL of 1 N HCl. Stopper the flask and allow to 
stand for 5 minutes. Titrate the solution with stock sodium thiosulfate 
solution (Section 8.2.8) to a pale yellow color. Add 5 mL of starch 
solution (Section 8.2.5) and titrate until the blue color just 
disappears. Calculate the normality (Ns) of the stock sodium 
thiosulfate solution as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.001

where:

M = volume of thiosulfate required in mL, and
W = weight of potassium iodate in g (recorded weight in Section 8.2.7).
[GRAPHIC] [TIFF OMITTED] TC08NO91.002

    8.2.9 Working sodium thiosulfate titrant (0.01 N): Accurately pipet 
100 mL of stock sodium thiosulfate solution (Section 8.2.8) into a 
1,000-mL volumetric flask and dilute to volume with freshly boiled, 
cooled, distilled water. Calculate the normality of the working sodium 
thiosulfate titrant (NT) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.003

    8.2.10 Standardized sulfite solution for the preparation of working 
sulfite-TCM solution: Dissolve 0.30 g sodium metabisulfite 
(Na2 S2 O5) or 0.40 g sodium sulfite 
(Na2 SO3) in 500 mL of recently boiled, cooled, 
distilled water. (Sulfite solution is unstable; it is therefore 
important to use water of the highest purity to minimize this 
instability.) This solution contains the equivalent of 320 to 400 
[micro]g SO2/mL. The actual concentration of the solution is 
determined by adding excess iodine and back-titrating with standard 
sodium thiosulfate solution. To back-titrate, pipet 50 mL of the 0.01 N 
iodine solution (Section 8.2.4) into each of two 500-mL iodine flasks (A 
and B). To flask A (blank) add 25 mL distilled water, and to flask B 
(sample)

[[Page 19]]

pipet 25 mL sulfite solution. Stopper the flasks and allow to stand for 
5 minutes. Prepare the working sulfite-TCM solution (Section 8.2.11) 
immediately prior to adding the iodine solution to the flasks. Using a 
buret containing standardized 0.01 N thiosulfate titrant (Section 
8.2.9), titrate the solution in each flask to a pale yellow color. Then 
add 5 mL starch solution (Section 8.2.5) and continue the titration 
until the blue color just disappears.
    8.2.11 Working sulfite-TCM solution: Accurately pipet 5 mL of the 
standard sulfite solution (Section 8.2.10) into a 250-mL volumetric 
flask and dilute to volume with 0.04 M TCM. Calculate the concentration 
of sulfur dioxide in the working solution as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.004

where:

A = volume of thiosulfate titrant required for the blank, mL;
B = volume of thiosulfate titrant required for the sample, mL;
NT = normality of the thiosulfate titrant, from equation (3);
32,000 = milliequivalent weight of SO2, [micro]g;
25 = volume of standard sulfite solution, mL; and
0.02 = dilution factor.

    This solution is stable for 30 days if kept at 5 [deg]C. (16) If not 
kept at 5 [deg]C, prepare fresh daily.
    8.2.12 Purified pararosaniline (PRA) stock solution (0.2% nominal):
    8.2.12.1 Dye specifications--

 The dye must have a maximum absorbance at a 
wavelength of 540 nm when assayed in a buffered solution of 0.1 M sodium 
acetate-acetic acid;
 The absorbance of the reagent blank, which is 
temperature sensitive (0.015 absorbance unit/ [deg]C), must not exceed 
0.170 at 22 [deg]C with a 1-cm optical path length when the blank is 
prepared according to the specified procedure;
 The calibration curve (Section 10.0) must have a 
slope equal to 0.030 0.002 absorbance unit/
[micro]g SO2 with a 1-cm optical path length when the dye is 
pure and the sulfite solution is properly standardized.

    8.2.12.2 Preparation of stock PRA solution--A specially purified (99 
to 100 percent pure) solution of pararosaniline, which meets the above 
specifications, is commercially available in the required 0.20 percent 
concentration (Harleco Co.). Alternatively, the dye may be purified, a 
stock solution prepared, and then assayed according to the procedure as 
described below.(10)
    8.2.12.3 Purification procedure for PRA--
    1. Place 100 mL each of 1-butanol and 1 N HCl in a large separatory 
funnel (250-mL) and allow to equilibrate. Note: Certain batches of 1-
butanol contain oxidants that create an SO2 demand. Before 
using, check by placing 20 mL of 1-butanol and 5 mL of 20 percent 
potassium iodide (KI) solution in a 50-mL separatory funnel and shake 
thoroughly. If a yellow color appears in the alcohol phase, redistill 
the 1-butanol from silver oxide and collect the middle fraction or 
purchase a new supply of 1-butanol.
    2. Weigh 100 mg of pararosaniline hydrochloride dye (PRA) in a small 
beaker. Add 50 mL of the equilibrated acid (drain in acid from the 
bottom of the separatory funnel in 1.) to the beaker and let stand for 
several minutes. Discard the remaining acid phase in the separatory 
funnel.
    3. To a 125-mL separatory funnel, add 50 mL of the equilibrated 1-
butanol (draw the 1-butanol from the top of the separatory funnel in 
1.). Transfer the acid solution (from 2.) containing the dye to the 
funnel and shake carefully to extract. The violet impurity will transfer 
to the organic phase.
    4. Transfer the lower aqueous phase into another separatory funnel, 
add 20 mL of equilibrated 1-butanol, and extract again.
    5. Repeat the extraction procedure with three more 10-mL portions of 
equilibrated 1-butanol.
    6. After the final extraction, filter the acid phase through a 
cotton plug into a 50-mL volumetric flask and bring to volume with 1 N 
HCl. This stock reagent will be a yellowish red.
    7. To check the purity of the PRA, perform the assay and adjustment 
of concentration (Section 8.2.12.4) and prepare a reagent blank (Section 
11.2); the absorbance of this reagent blank at 540 nm should be less 
than 0.170 at 22 [deg]C. If the absorbance is greater than 0.170 under 
these conditions, further extractions should be performed.
    8.2.12.4 PRA assay procedure--The concentration of pararosaniline 
hydrochloride (PRA) need be assayed only once after purification. It is 
also recommended that commercial solutions of pararosaniline be assayed 
when first purchased. The assay procedure is as follows:(10)
    1. Prepare 1 M acetate-acetic acid buffer stock solution with a pH 
of 4.79 by dissolving

[[Page 20]]

13.61 g of sodium acetate trihydrate in distilled water in a 100-mL 
volumetric flask. Add 5.70 mL of glacial acetic acid and dilute to 
volume with distilled water.
    2. Pipet 1 mL of the stock PRA solution obtained from the 
purification process or from a commercial source into a 100-mL 
volumetric flask and dilute to volume with distilled water.
    3. Transfer a 5-mL aliquot of the diluted PRA solution from 2. into 
a 50-mL volumetric flask. Add 5mL of 1 M acetate-acetic acid buffer 
solution from 1. and dilute the mixture to volume with distilled water. 
Let the mixture stand for 1 hour.
    4. Measure the absorbance of the above solution at 540 nm with a 
spectrophotometer against a distilled water reference. Compute the 
percentage of nominal concentration of PRA by
[GRAPHIC] [TIFF OMITTED] TC08NO91.005

where:

A = measured absorbance of the final mixture (absorbance units);
W = weight in grams of the PRA dye used in the assay to prepare 50 mL of 
stock solution (for example, 0.100 g of dye was used to prepare 50 mL of 
solution in the purification procedure; when obtained from commercial 
sources, use the stated concentration to compute W; for 98% PRA, W=.098 
g.); and
K = 21.3 for spectrophotometers having a spectral bandwidth of less than 
15 nm and a path length of 1 cm.

    8.2.13 Pararosaniline reagent: To a 250-mL volumetric flask, add 20 
mL of stock PRA solution. Add an additional 0.2 mL of stock solution for 
each percentage that the stock assays below 100 percent. Then add 25 mL 
of 3 M phosphoric acid and dilute to volume with distilled water. The 
reagent is stable for at least 9 months. Store away from heat and light.
    9.0 Sampling Procedure.
    9.1 General Considerations. Procedures are described for short-term 
sampling (30-minute and 1-hour) and for long-term sampling (24-hour). 
Different combinations of absorbing reagent volume, sampling rate, and 
sampling time can be selected to meet special needs. For combinations 
other than those specifically described, the conditions must be adjusted 
so that linearity is maintained between absorbance and concentration 
over the dynamic range. Absorbing reagent volumes less than 10 mL are 
not recommended. The collection efficiency is above 98 percent for the 
conditions described; however, the efficiency may be substantially lower 
when sampling concentrations below 25 [micro][gamma]SO2/
m\3\.(8,9)
    9.2 30-Minute and 1-Hour Sampling. Place 10 mL of TCM absorbing 
reagent in a midget impinger and seal the impinger with a thin film of 
silicon stopcock grease (around the ground glass joint). Insert the 
sealed impinger into the sampling train as shown in Figure 1, making 
sure that all connections between the various components are leak tight. 
Greaseless ball joint fittings, heat shrinkable Teflon [reg] 
tubing, or Teflon [reg] tube fittings may be used to attain 
leakfree conditions for portions of the sampling train that come into 
contact with air containing SO2. Shield the absorbing reagent 
from direct sunlight by covering the impinger with aluminum foil or by 
enclosing the sampling train in a light-proof box. Determine the flow 
rate according to Section 9.4.2. Collect the sample at 1 0.10 L/min for 30-minute sampling or 0.500 0.05 L/min for 1-hour sampling. Record the exact 
sampling time in minutes, as the sample volume will later be determined 
using the sampling flow rate and the sampling time. Record the 
atmospheric pressure and temperature.
    9.3 24-Hour Sampling. Place 50 mL of TCM absorbing solution in a 
large absorber, close the cap, and, if needed, apply the heat shrink 
material as shown in Figure 3. Verify that the reagent level is at the 
50 mL mark on the absorber. Insert the sealed absorber into the sampling 
train as shown in Figure 2. At this time verify that the absorber 
temperature is controlled to 15 10 [deg]C. During 
sampling, the absorber temperature must be controlled to prevent 
decomposition of the collected complex. From the onset of sampling until 
analysis, the absorbing solution must be protected from direct sunlight. 
Determine the flow rate according to Section 9.4.2. Collect the sample 
for 24 hours from midnight to midnight at a flow rate of 0.200 0.020 L/min. A start/stop timer is helpful for 
initiating and stopping sampling and an elapsed time meter will be 
useful for determining the sampling time.

[[Page 21]]



    9.4 Flow Measurement.
    9.4.1 Calibration: Flow measuring devices used for the on-site flow 
measurements required in 9.4.2 must be calibrated against a reliable 
flow or volume standard such as an NBS traceable bubble flowmeter or 
calibrated wet test meter. Rotameters or critical orifices used in the 
sampling train may be calibrated, if desired, as a quality control 
check, but such calibration shall not replace the on-site flow 
measurements required by 9.4.2. In-line rotameters, if they are to be 
calibrated, should be calibrated in situ, with the appropriate volume of 
solution in the absorber.
    9.4.2 Determination of flow rate at sampling site: For short-term 
samples, the standard flow rate is determined at the sampling site at 
the initiation and completion of sample collection with a calibrated 
flow measuring device connected to the inlet of the absorber. For 24-
hour samples, the standard flow rate is determined at the time the 
absorber is placed in the sampling train and again when the absorber is 
removed from the train for shipment to the analytical laboratory with a 
calibrated flow measuring device connected to the inlet of the sampling 
train. The flow rate determination must be made with all components of 
the sampling system in operation (e.g., the absorber temperature 
controller and any sample box heaters must also be operating). Equation 
6 may be used to determine the standard flow rate when a calibrated 
positive displacement meter is used as the flow measuring device. Other 
types of calibrated flow measuring devices may also be used to determine 
the flow rate at the sampling site provided that the user applies any 
appropriate corrections to devices for which output is dependent on 
temperature or pressure.

[[Page 22]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.006

where:

Qstd = flow rate at standard conditions, std L/min (25 [deg]C 
and 760 mm Hg);
Qact = flow rate at monitoring site conditions, L/min;
Pb = barometric pressure at monitoring site conditions, mm Hg 
or kPa;
RH = fractional relative humidity of the air being measured;
PH2O = vapor pressure of water at the temperature 
of the air in the flow or volume standard, in the same units as 
Pb, (for wet volume standards only, i.e., bubble flowmeter or 
wet test meter; for dry standards, i.e., dry test meter, 
PH2O=0);
Pstd = standard barometric pressure, in the same units as 
Pb (760 mm Hg or 101 kPa); and
Tmeter = temperature of the air in the flow or volume 
standard, [deg]C (e.g., bubble flowmeter).

    If a barometer is not available, the following equation may be used 
to determine the barometric pressure:
[GRAPHIC] [TIFF OMITTED] TC08NO91.007

where:

H = sampling site elevation above sea level in meters.

    If the initial flow rate (Qi) differs from the flow rate 
of the critical orifice or the flow rate indicated by the flowmeter in 
the sampling train (Qc) by more than 5 percent as determined 
by equation (8), check for leaks and redetermine Qi.
[GRAPHIC] [TIFF OMITTED] TC08NO91.008

    Invalidate the sample if the difference between the initial 
(Qi) and final (Qf) flow rates is more than 5 
percent as determined by equation (9):
[GRAPHIC] [TIFF OMITTED] TC08NO91.009

    9.5 Sample Storage and Shipment. Remove the impinger or absorber 
from the sampling train and stopper immediately. Verify that the 
temperature of the absorber is not above 25 [deg]C. Mark the level of 
the solution with a temporary (e.g., grease pencil) mark. If the sample 
will not be analyzed within 12 hours of sampling, it must be stored at 
5[deg] 5 [deg]C until analysis. Analysis must 
occur within 30 days. If the sample is transported or shipped for a 
period exceeding 12 hours, it is recommended that thermal coolers using 
eutectic ice packs, refrigerated shipping containers, etc., be used for 
periods up to 48 hours. (17) Measure the temperature of the absorber 
solution when the shipment is received. Invalidate the sample if the 
temperature is above 10 [deg]C. Store the sample at 5[deg] 5 [deg]C until it is analyzed.
    10.0 Analytical Calibration.
    10.1 Spectrophotometer Cell Matching. If unmatched spectrophotometer 
cells are used, an absorbance correction factor must be determined as 
follows:
    1. Fill all cells with distilled water and designate the one that 
has the lowest absorbance at 548 nm as the reference. (This reference 
cell should be marked as such and continually used for this purpose 
throughout all future analyses.)
    2. Zero the spectrophotometer with the reference cell.
    3. Determine the absorbance of the remaining cells (Ac) 
in relation to the reference cell and record these values for future 
use. Mark all cells in a manner that adequately identifies the 
correction.
    The corrected absorbance during future analyses using each cell is 
determining as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.010

where:

A = corrected absorbance,
Aobs = uncorrected absorbance, and
Ac = cell correction.

    10.2 Static Calibration Procedure (Option 1). Prepare a dilute 
working sulfite-TCM solution by diluting 10 mL of the working sulfite-
TCM solution (Section 8.2.11) to 100 mL with TCM absorbing reagent. 
Following the table below, accurately pipet the indicated volumes of the 
sulfite-TCM solutions into a series of 25-mL volumetric flasks. Add TCM 
absorbing reagent as indicated to bring the volume in each flask to 10 
mL.

[[Page 23]]



------------------------------------------------------------------------
                                         Volume of               Total
                                          sulfite-  Volume of   [micro]g
          Sulfite-TCM solution              TCM      TCM, mL      SO2
                                          solution             (approx.*
------------------------------------------------------------------------
Working................................        4.0        6.0       28.8
Working................................        3.0        7.0       21.6
Working................................        2.0        8.0       14.4
Dilute working.........................       10.0        0.0        7.2
Dilute working.........................        5.0        5.0        3.6
                                               0.0       10.0        0.0
------------------------------------------------------------------------
*Based on working sulfite-TCM solution concentration of 7.2 [micro]g SO2/
  mL; the actual total [micro]g SO2 must be calculated using equation 11
  below.

    To each volumetric flask, add 1 mL 0.6% sulfamic acid (Section 
8.2.1), accurately pipet 2 mL 0.2% formaldehyde solution (Section 
8.2.2), then add 5 mL pararosaniline solution (Section 8.2.13). Start a 
laboratory timer that has been set for 30 minutes. Bring all flasks to 
volume with recently boiled and cooled distilled water and mix 
thoroughly. The color must be developed (during the 30-minute period) in 
a temperature environment in the range of 20[deg] to 30 [deg]C, which is 
controlled to 1 [deg]C. For increased precision, a 
constant temperature bath is recommended during the color development 
step. After 30 minutes, determine the corrected absorbance of each 
standard at 548 nm against a distilled water reference (Section 10.1). 
Denote this absorbance as (A). Distilled water is used in the reference 
cell rather than the reagant blank because of the temperature 
sensitivity of the reagent blank. Calculate the total micrograms 
SO2 in each solution:
[GRAPHIC] [TIFF OMITTED] TC08NO91.011

where:

VTCM/SO2 = volume of sulfite-TCM solution used, mL;
CTCM/SO2 = concentration of sulfur dioxide in the working 
sulfite-TCM, [micro]g SO2/mL (from equation 4); and
D = dilution factor (D = 1 for the working sulfite-TCM solution; D = 0.1 
for the diluted working sulfite-TCM solution).

    A calibration equation is determined using the method of linear 
least squares (Section 12.1). The total micrograms SO2 
contained in each solution is the x variable, and the corrected 
absorbance (eq. 10) associated with each solution is the y variable. For 
the calibration to be valid, the slope must be in the range of 0.030 
0.002 absorbance unit/[micro]g SO2, the 
intercept as determined by the least squares method must be equal to or 
less than 0.170 absorbance unit when the color is developed at 22 [deg]C 
(add 0.015 to this 0.170 specification for each [deg]C above 22 [deg]C) 
and the correlation coefficient must be greater than 0.998. If these 
criteria are not met, it may be the result of an impure dye and/or an 
improperly standardized sulfite-TCM solution. A calibration factor 
(Bs) is determined by calculating the reciprocal of the slope 
and is subsequently used for calculating the sample concentration 
(Section 12.3).
    10.3 Dynamic Calibration Procedures (Option 2). Atmospheres 
containing accurately known concentrations of sulfur dioxide are 
prepared using permeation devices. In the systems for generating these 
atmospheres, the permeation device emits gaseous SO2 at a 
known, low, constant rate, provided the temperature of the device is 
held constant (0.1 [deg]C) and the device has been 
accurately calibrated at the temperature of use. The SO2 
permeating from the device is carried by a low flow of dry carrier gas 
to a mixing chamber where it is diluted with SO2-free air to 
the desired concentration and supplied to a vented manifold. A typical 
system is shown schematically in Figure 4 and this system and other 
similar systems have been described in detail by O'Keeffe and Ortman; 
(19) Scaringelli, Frey, and Saltzman, (20) and Scaringelli, O'Keeffe, 
Rosenberg, and Bell. (21) Permeation devices may be prepared or 
purchased and in both cases must be traceable either to a National 
Bureau of Standards (NBS) Standard Reference Material (SRM 1625, SRM 
1626, SRM 1627) or to an NBS/EPA-approved commercially available 
Certified Reference Material (CRM). CRM's are described in Reference 22, 
and a list of CRM sources is available from the address shown for 
Reference 22. A recommended protocol for certifying a permeation device 
to an NBS SRM or CRM is given in Section 2.0.7 of Reference 2. Device 
permeation rates of 0.2 to 0.4 [micro]g/min, inert gas flows of about 50 
mL/min, and dilution air flow rates from 1.1 to 15 L/min conveniently 
yield standard atmospheres in the range of 25 to 600 [micro]g 
SO2/m\3\ (0.010 to 0.230 ppm).
    10.3.1 Calibration Option 2A (30-minute and 1-hour samples): 
Generate a series of six standard atmospheres of SO2 (e.g., 
0, 50, 100, 200, 350, 500, 750 [micro]g/m\3\) by adjusting the dilution 
flow rates appropriately. The concentration of SO2 in each 
atmosphere is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.014

where:


[[Page 24]]


Ca = concentration of SO2 at standard conditions, 
[micro]g/m\3\;
Pr = permeation rate, [micro]g/min;
Qd = flow rate of dilution air, std L/min; and
Qp = flow rate of carrier gas across permeation device, std 
L/min.



[[Page 25]]


    Be sure that the total flow rate of the standard exceeds the flow 
demand of the sample train, with the excess flow vented at atmospheric 
pressure. Sample each atmosphere using similar apparatus as shown in 
Figure 1 and under the same conditions as field sampling (i.e., use same 
absorbing reagent volume and sample same volume of air at an equivalent 
flow rate). Due to the length of the sampling periods required, this 
method is not recommended for 24-hour sampling. At the completion of 
sampling, quantitatively transfer the contents of each impinger to one 
of a series of 25-mL volumetric flasks (if 10 mL of absorbing solution 
was used) using small amounts of distilled water for rinse (<5mL). If 
10 mL of absorbing solution was used, bring the absorber 
solution in each impinger to orginal volume with distilled H2 
O and pipet 10-mL portions from each impinger into a series of 25-mL 
volumetric flasks. If the color development steps are not to be started 
within 12 hours of sampling, store the solutions at 5[deg] 5 [deg]C. Calculate the total micrograms SO2 
in each solution as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.015

where:

Ca = concentration of SO2 in the standard 
atmosphere, [micro]g/m\3\;
Os = sampling flow rate, std L/min;
t=sampling time, min;
Va = volume of absorbing solution used for color development 
(10 mL); and
Vb = volume of absorbing solution used for sampling, mL.

    Add the remaining reagents for color development in the same manner 
as in Section 10.2 for static solutions. Calculate a calibration 
equation and a calibration factor (Bg) according to Section 
10.2, adhering to all the specified criteria.
    10.3.2 Calibration Option 2B (24-hour samples): Generate a standard 
atmosphere containing approximately 1,050 [micro]g SO2/m\3\ 
and calculate the exact concentration according to equation 12. Set up a 
series of six absorbers according to Figure 2 and connect to a common 
manifold for sampling the standard atmosphere. Be sure that the total 
flow rate of the standard exceeds the flow demand at the sample 
manifold, with the excess flow vented at atmospheric pressure. The 
absorbers are then allowed to sample the atmosphere for varying time 
periods to yield solutions containing 0, 0.2, 0.6, 1.0, 1.4, 1.8, and 
2.2 [micro]g SO2/mL solution. The sampling times required to 
attain these solution concentrations are calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.016

where:

t = sampling time, min;
Vb = volume of absorbing solution used for sampling (50 mL);
Cs = desired concentration of SO2 in the absorbing 
solution, [micro]g/mL;
Ca = concentration of the standard atmosphere calculated 
according to equation 12, [micro]g/m\3\; and
Qs = sampling flow rate, std L/min.

    At the completion of sampling, bring the absorber solutions to 
original volume with distilled water. Pipet a 10-mL portion from each 
absorber into one of a series of 25-mL volumetric flasks. If the color 
development steps are not to be started within 12 hours of sampling, 
store the solutions at 5[deg] 5 [deg]C. Add the 
remaining reagents for color development in the same manner as in 
Section 10.2 for static solutions. Calculate the total [micro]g 
SO2 in each standard as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.017

where:

Va = volume of absorbing solution used for color development 
(10 mL).
All other parameters are defined in equation 14.

    Calculate a calibration equation and a calibration factor 
(Bt) according to Section 10.2 adhering to all the specified 
criteria.
    11.0 Sample Preparation and Analysis.
    11.1 Sample Preparation. Remove the samples from the shipping 
container. If the shipment period exceeded 12 hours from the completion 
of sampling, verify that the temperature is below 10 [deg]C. Also, 
compare the solution level to the temporary level mark on the absorber. 
If either the temperature is above 10 [deg]C or there was significant 
loss (more than 10 mL) of the sample during shipping, make an 
appropriate notation in the record and invalidate the sample. Prepare 
the samples for analysis as follows:
    1. For 30-minute or 1-hour samples: Quantitatively transfer the 
entire 10 mL amount of absorbing solution to a 25-mL volumetric flask 
and rinse with a small amount (<5 mL) of distilled water.
    2. For 24-hour samples: If the volume of the sample is less than the 
original 50-mL volume (permanent mark on the absorber), adjust the 
volume back to the original volume with distilled water to compensate 
for water lost to evaporation during sampling. If the final volume is 
greater than the original volume, the volume must be measured using a 
graduated cylinder. To analyze, pipet 10 mL

[[Page 26]]

of the solution into a 25-mL volumetric flask.
    11.2 Sample Analysis. For each set of determinations, prepare a 
reagent blank by adding 10 mL TCM absorbing solution to a 25-mL 
volumetric flask, and two control standards containing approximately 5 
and 15 [micro]g SO2, respectively. The control standards are 
prepared according to Section 10.2 or 10.3. The analysis is carried out 
as follows:
    1. Allow the sample to stand 20 minutes after the completion of 
sampling to allow any ozone to decompose (if applicable).
    2. To each 25-mL volumetric flask containing reagent blank, sample, 
or control standard, add 1 mL of 0.6% sulfamic acid (Section 8.2.1) and 
allow to react for 10 min.
    3. Accurately pipet 2 mL of 0.2% formaldehyde solution (Section 
8.2.2) and then 5 mL of pararosaniline solution (Section 8.2.13) into 
each flask. Start a laboratory timer set at 30 minutes.
    4. Bring each flask to volume with recently boiled and cooled 
distilled water and mix thoroughly.
    5. During the 30 minutes, the solutions must be in a temperature 
controlled environment in the range of 20[deg] to 30 [deg]C maintained 
to 1 [deg]C. This temperature must also be within 
1 [deg]C of that used during calibration.
    6. After 30 minutes and before 60 minutes, determine the corrected 
absorbances (equation 10) of each solution at 548 nm using 1-cm optical 
path length cells against a distilled water reference (Section 10.1). 
(Distilled water is used as a reference instead of the reagent blank 
because of the sensitivity of the reagent blank to temperature.)
    7. Do not allow the colored solution to stand in the cells because a 
film may be deposited. Clean the cells with isopropyl alcohol after use.
    8. The reagent blank must be within 0.03 absorbance units of the 
intercept of the calibration equation determined in Section 10.
    11.3 Absorbance range. If the absorbance of the sample solution 
ranges between 1.0 and 2.0, the sample can be diluted 1:1 with a portion 
of the reagent blank and the absorbance redetermined within 5 minutes. 
Solutions with higher absorbances can be diluted up to sixfold with the 
reagent blank in order to obtain scale readings of less than 1.0 
absorbance unit. However, it is recommended that a smaller portion (<10 
mL) of the original sample be reanalyzed (if possible) if the sample 
requires a dilution greater than 1:1.
    11.4 Reagent disposal. All reagents containing mercury compounds 
must be stored and disposed of using one of the procedures contained in 
Section 13. Until disposal, the discarded solutions can be stored in 
closed glass containers and should be left in a fume hood.
    12.0 Calculations.
    12.1 Calibration Slope, Intercept, and Correlation Coefficient. The 
method of least squares is used to calculate a calibration equation in 
the form of:
[GRAPHIC] [TIFF OMITTED] TC08NO91.012

where:

y = corrected absorbance,
m = slope, absorbance unit/[micro]g SO2,
x = micrograms of SO2,
b = y intercept (absorbance units).

    The slope (m), intercept (b), and correlation coefficient (r) are 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.018

[GRAPHIC] [TIFF OMITTED] TR31AU93.019

[GRAPHIC] [TIFF OMITTED] TR31AU93.020

where n is the number of calibration points.
    A data form (Figure 5) is supplied for easily organizing calibration 
data when the slope, intercept, and correlation coefficient are 
calculated by hand.
    12.2 Total Sample Volume. Determine the sampling volume at standard 
conditions as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.021

where:

Vstd = sampling volume in std L,
Qi = standard flow rate determined at the initiation of 
sampling in std L/min,
Qf = standard flow rate determined at the completion of 
sampling is std L/min, and
t = total sampling time, min.

    12.3 Sulfur Dioxide Concentration. Calculate and report the 
concentration of each sample as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.022

where:

A = corrected absorbance of the sample solution, from equation (10);
Ao = corrected absorbance of the reagent blank, using 
equation (10);
BX = calibration factor equal to Bs, 
Bg, or Bt depending on the calibration procedure 
used, the reciprocal of the slope of the calibration equation;
Va = volume of absorber solution analyzed, mL;
Vb = total volume of solution in absorber (see 11.1-2), mL; 
and
Vstd = standard air volume sampled, std L (from Section 
12.2).

[[Page 27]]



                                                    Data Form
                                             [For hand calculations]
----------------------------------------------------------------------------------------------------------------
                                                      Absor- bance
     Calibration point no.       Micro- grams So2        units
----------------------------------------------------------------------------------------------------------------
                                       (x)                (y)                x\2\               xy          y\2\
1.............................  .................  .................  .................  ................  .....
2.............................  .................  .................  .................  ................  .....
3.............................  .................  .................  .................  ................  .....
4.............................  .................  .................  .................  ................  .....
5.............................  .................  .................  .................  ................  .....
6.............................  .................  .................  .................  ................  .....
----------------------------------------------------------------------------------------------------------------

[Sigma] x=------ [Sigma] y=------ [Sigma] x\2\=------ [Sigma]xy------ 
[Sigma]y\2\------
n=------ (number of pairs of coordinates.)
________________________________________________________________________

Figure 5. Data form for hand calculations.

    12.4 Control Standards. Calculate the analyzed micrograms of 
SO2 in each control standard as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.070

where:

Cq = analyzed [micro]g SO2 in each control 
standard,
A = corrected absorbance of the control standard, and
Ao = corrected absorbance of the reagent blank.

    The difference between the true and analyzed values of the control 
standards must not be greater than 1 [micro]g. If the difference is 
greater than 1 [micro]g, the source of the discrepancy must be 
identified and corrected.
    12.5 Conversion of [micro]g/m\3\ to ppm (v/v). If desired, the 
concentration of sulfur dioxide at reference conditions can be converted 
to ppm SO2 (v/v) as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.023

    13.0 The TCM absorbing solution and any reagents containing mercury 
compounds must be treated and disposed of by one of the methods 
discussed below. Both methods remove greater than 99.99 percent of the 
mercury.
    13.1 Disposal of Mercury-Containing Solutions.
    13.2 Method for Forming an Amalgam.
    1. Place the waste solution in an uncapped vessel in a hood.
    2. For each liter of waste solution, add approximately 10 g of 
sodium carbonate until neutralization has occurred (NaOH may have to be 
used).
    3. Following neutralization, add 10 g of granular zinc or magnesium.
    4. Stir the solution in a hood for 24 hours. Caution must be 
exercised as hydrogen gas is evolved by this treatment process.
    5. After 24 hours, allow the solution to stand without stirring to 
allow the mercury amalgam (solid black material) to settle to the bottom 
of the waste receptacle.
    6. Upon settling, decant and discard the supernatant liquid.
    7. Quantitatively transfer the solid material to a container and 
allow to dry.
    8. The solid material can be sent to a mercury reclaiming plant. It 
must not be discarded.
    13.3 Method Using Aluminum Foil Strips.
    1. Place the waste solution in an uncapped vessel in a hood.
    2. For each liter of waste solution, add approximately 10 g of 
aluminum foil strips. If all the aluminum is consumed and no gas is 
evolved, add an additional 10 g of foil. Repeat until the foil is no 
longer consumed and allow the gas to evolve for 24 hours.
    3. Decant the supernatant liquid and discard.
    4. Transfer the elemental mercury that has settled to the bottom of 
the vessel to a storage container.
    5. The mercury can be sent to a mercury reclaiming plant. It must 
not be discarded.
    14.0 References for SO2 Method.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1976.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 1977.
    3. Dasqupta, P. K., and K. B. DeCesare. Stability of Sulfur Dioxide 
in Formaldehyde and Its Anomalous Behavior in Tetrachloromercurate (II). 
Submitted for publication in Atmospheric Environment, 1982.
    4. West, P. W., and G. C. Gaeke. Fixation of Sulfur Dioxide as 
Disulfitomercurate (II) and Subsequent Colorimetric Estimation. Anal. 
Chem., 28:1816, 1956.
    5. Ephraim, F. Inorganic Chemistry. P. C. L. Thorne and E. R. 
Roberts, Eds., 5th Edition, Interscience, 1948, p. 562.
    6. Lyles, G. R., F. B. Dowling, and V. J. Blanchard. Quantitative 
Determination of Formaldehyde in the Parts Per Hundred Million 
Concentration Level. J. Air. Poll. Cont. Assoc., Vol. 15(106), 1965.
    7. McKee, H. C., R. E. Childers, and O. Saenz, Jr. Collaborative 
Study of Reference Method for Determination of Sulfur Dioxide in the 
Atmosphere (Pararosaniline Method). EPA-APTD-0903, U.S. Environmental 
Protection Agency, Research Triangle Park, NC 27711, September 1971.
    8. Urone, P., J. B. Evans, and C. M. Noyes. Tracer Techniques in 
Sulfur--Air Pollution Studies Apparatus and Studies of Sulfur Dioxide 
Colorimetric and Conductometric Methods. Anal. Chem., 37: 1104, 1965.

[[Page 28]]

    9. Bostrom, C. E. The Absorption of Sulfur Dioxide at Low 
Concentrations (pphm) Studied by an Isotopic Tracer Method. Intern. J. 
Air Water Poll., 9:333, 1965.
    10. Scaringelli, F. P., B. E. Saltzman, and S. A. Frey. 
Spectrophotometric Determination of Atmospheric Sulfur Dioxide. Anal. 
Chem., 39: 1709, 1967.
    11. Pate, J. B., B. E. Ammons, G. A. Swanson, and J. P. Lodge, Jr. 
Nitrite Interference in Spectrophotometric Determination of Atmospheric 
Sulfur Dioxide. Anal. Chem., 37:942, 1965.
    12. Zurlo, N., and A. M. Griffini. Measurement of the Sulfur Dioxide 
Content of the Air in the Presence of Oxides of Nitrogen and Heavy 
Metals. Medicina Lavoro, 53:330, 1962.
    13. Rehme, K. A., and F. P. Scaringelli. Effect of Ammonia on the 
Spectrophotometric Determination of Atmospheric Concentrations of Sulfur 
Dioxide. Anal. Chem., 47:2474, 1975.
    14. McCoy, R. A., D. E. Camann, and H. C. McKee. Collaborative Study 
of Reference Method for Determination of Sulfur Dioxide in the 
Atmosphere (Pararosaniline Method) (24-Hour Sampling). EPA-650/4-74-027, 
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, 
December 1973.
    15. Fuerst, R. G. Improved Temperature Stability of Sulfur Dioxide 
Samples Collected by the Federal Reference Method. EPA-600/4-78-018, 
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, 
April 1978.
    16. Scaringelli, F. P., L. Elfers, D. Norris, and S. Hochheiser. 
Enhanced Stability of Sulfur Dioxide in Solution. Anal. Chem., 42:1818, 
1970.
    17. Martin, B. E. Sulfur Dioxide Bubbler Temperature Study. EPA-600/
4-77-040, U.S. Environmental Protection Agency, Research Triangle Park, 
NC 27711, August 1977.
    18. American Society for Testing and Materials. ASTM Standards, 
Water; Atmospheric Analysis. Part 23. Philadelphia, PA, October 1968, p. 
226.
    19. O'Keeffe, A. E., and G. C. Ortman. Primary Standards for Trace 
Gas Analysis. Anal. Chem., 38:760, 1966.
    20. Scaringelli, F. P., S. A. Frey, and B. E. Saltzman. Evaluation 
of Teflon Permeation Tubes for Use with Sulfur Dioxide. Amer. Ind. 
Hygiene Assoc. J., 28:260, 1967.
    21. Scaringelli, F. P., A. E. O'Keeffe, E. Rosenberg, and J. P. 
Bell, Preparation of Known Concentrations of Gases and Vapors With 
Permeation Devices Calibrated Gravimetrically. Anal. Chem., 42:871, 
1970.
    22. A Procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, U.S. Environmental Protection Agency, Environmental 
Monitoring Systems Laboratory (MD-77), Research Triangle Park, NC 27711, 
January 1981.

[47 FR 54899, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]



 Sec. Appendix B to Part 50--Reference Method for the Determination of 
   Suspended Particulate Matter in the Atmosphere (High-Volume Method)

    1.0 Applicability.
    1.1 This method provides a measurement of the mass concentration of 
total suspended particulate matter (TSP) in ambient air for determining 
compliance with the primary and secondary national ambient air quality 
standards for particulate matter as specified in Sec. 50.6 and Sec. 
50.7 of this chapter. The measurement process is nondestructive, and the 
size of the sample collected is usually adequate for subsequent chemical 
analysis. Quality assurance procedures and guidance are provided in part 
58, appendixes A and B, of this chapter and in References 1 and 2.
    2.0 Principle.
    2.1 An air sampler, properly located at the measurement site, draws 
a measured quantity of ambient air into a covered housing and through a 
filter during a 24-hr (nominal) sampling period. The sampler flow rate 
and the geometry of the shelter favor the collection of particles up to 
25-50 [micro]m (aerodynamic diameter), depending on wind speed and 
direction.(3) The filters used are specified to have a minimum 
collection efficiency of 99 percent for 0.3 [micro]m (DOP) particles 
(see Section 7.1.4).
    2.2 The filter is weighed (after moisture equilibration) before and 
after use to determine the net weight (mass) gain. The total volume of 
air sampled, corrected to EPA standard conditions (25 [deg]C, 760 mm Hg 
[101 kPa]), is determined from the measured flow rate and the sampling 
time. The concentration of total suspended particulate matter in the 
ambient air is computed as the mass of collected particles divided by 
the volume of air sampled, corrected to standard conditions, and is 
expressed in micrograms per standard cubic meter ([micro]g/std m\3\). 
For samples collected at temperatures and pressures significantly 
different than standard conditions, these corrected concentrations may 
differ substantially from actual concentrations (micrograms per actual 
cubic meter), particularly at high elevations. The actual particulate 
matter concentration can be calculated from the corrected concentration 
using the actual temperature and pressure during the sampling period.
    3.0 Range.
    3.1 The approximate concentration range of the method is 2 to 750 
[micro]g/std m\3\. The upper limit is determined by the point at which 
the sampler can no longer maintain the specified

[[Page 29]]

flow rate due to the increased pressure drop of the loaded filter. This 
point is affected by particle size distribution, moisture content of the 
collected particles, and variability from filter to filter, among other 
things. The lower limit is determined by the sensitivity of the balance 
(see Section 7.10) and by inherent sources of error (see Section 6).
    3.2 At wind speeds between 1.3 and 4.5 m/sec (3 and 10 mph), the 
high-volume air sampler has been found to collect particles up to 25 to 
50 [micro]m, depending on wind speed and direction.(3) For the filter 
specified in Section 7.1, there is effectively no lower limit on the 
particle size collected.
    4.0 Precision.
    4.1 Based upon collaborative testing, the relative standard 
deviation (coefficient of variation) for single analyst precision 
(repeatability) of the method is 3.0 percent. The corresponding value 
for interlaboratory precision (reproducibility) is 3.7 percent.(4)
    5.0 Accuracy.
    5.1 The absolute accuracy of the method is undefined because of the 
complex nature of atmospheric particulate matter and the difficulty in 
determining the ``true'' particulate matter concentration. This method 
provides a measure of particulate matter concentration suitable for the 
purpose specified under Section 1.0, Applicability.
    6.0 Inherent Sources of Error.
    6.1 Airflow variation. The weight of material collected on the 
filter represents the (integrated) sum of the product of the 
instantaneous flow rate times the instantaneous particle concentration. 
Therefore, dividing this weight by the average flow rate over the 
sampling period yields the true particulate matter concentration only 
when the flow rate is constant over the period. The error resulting from 
a nonconstant flow rate depends on the magnitude of the instantaneous 
changes in the flow rate and in the particulate matter concentration. 
Normally, such errors are not large, but they can be greatly reduced by 
equipping the sampler with an automatic flow controlling mechanism that 
maintains constant flow during the sampling period. Use of a contant 
flow controller is recommended.*
---------------------------------------------------------------------------

    *At elevated altitudes, the effectiveness of automatic flow 
controllers may be reduced because of a reduction in the maximum sampler 
flow.
---------------------------------------------------------------------------

    6.2 Air volume measurement. If the flow rate changes substantially 
or nonuniformly during the sampling period, appreciable error in the 
estimated air volume may result from using the average of the 
presampling and postsampling flow rates. Greater air volume measurement 
accuracy may be achieved by (1) equipping the sampler with a flow 
controlling mechanism that maintains constant air flow during the 
sampling period,* (2) using a calibrated, continuous flow rate recording 
device to record the actual flow rate during the samping period and 
integrating the flow rate over the period, or (3) any other means that 
will accurately measure the total air volume sampled during the sampling 
period. Use of a continuous flow recorder is recommended, particularly 
if the sampler is not equipped with a constant flow controller.
    6.3 Loss of volatiles. Volatile particles collected on the filter 
may be lost during subsequent sampling or during shipment and/or storage 
of the filter prior to the postsampling weighing.(5) Although such 
losses are largely unavoidable, the filter should be reweighed as soon 
after sampling as practical.
    6.4 Artifact particulate matter. Artifact particulate matter can be 
formed on the surface of alkaline glass fiber filters by oxidation of 
acid gases in the sample air, resulting in a higher than true TSP 
determination.(6 7) This effect usually occurs early in the sample 
period and is a function of the filter pH and the presence of acid 
gases. It is generally believed to account for only a small percentage 
of the filter weight gain, but the effect may become more significant 
where relatively small particulate weights are collected.
    6.5 Humidity. Glass fiber filters are comparatively insensitive to 
changes in relative humidity, but collected particulate matter can be 
hygroscopic.(8) The moisture conditioning procedure minimizes but may 
not completely eliminate error due to moisture.
    6.6 Filter handling. Careful handling of the filter between the 
presampling and postsampling weighings is necessary to avoid errors due 
to loss of fibers or particles from the filter. A filter paper cartridge 
or cassette used to protect the filter can minimize handling errors. 
(See Reference 2, Section 2).
    6.7 Nonsampled particulate matter. Particulate matter may be 
deposited on the filter by wind during periods when the sampler is 
inoperative. (9) It is recommended that errors from this source be 
minimized by an automatic mechanical device that keeps the filter 
covered during nonsampling periods, or by timely installation and 
retrieval of filters to minimize the nonsampling periods prior to and 
following operation.
    6.8 Timing errors. Samplers are normally controlled by clock timers 
set to start and stop the sampler at midnight. Errors in the nominal 
1,440-min sampling period may result from a power interruption during 
the sampling period or from a discrepancy between the start or stop time 
recorded on the filter information record and the actual start or stop 
time of the sampler. Such discrepancies may be caused by (1) poor 
resolution of the timer set-points, (2) timer error due to power 
interruption, (3) missetting of

[[Page 30]]

the timer, or (4) timer malfunction. In general, digital electronic 
timers have much better set-point resolution than mechanical timers, but 
require a battery backup system to maintain continuity of operation 
after a power interruption. A continuous flow recorder or elapsed time 
meter provides an indication of the sampler run-time, as well as 
indication of any power interruption during the sampling period and is 
therefore recommended.
    6.9 Recirculation of sampler exhaust. Under stagnant wind 
conditions, sampler exhaust air can be resampled. This effect does not 
appear to affect the TSP measurement substantially, but may result in 
increased carbon and copper in the collected sample. (10) This problem 
can be reduced by ducting the exhaust air well away, preferably 
downwind, from the sampler.
    7.0 Apparatus.
    (See References 1 and 2 for quality assurance information.)

    Note: Samplers purchased prior to the effective date of this 
amendment are not subject to specifications preceded by ([dagger]).

    7.1 Filter. (Filters supplied by the Environmental Protection Agency 
can be assumed to meet the following criteria. Additional specifications 
are required if the sample is to be analyzed chemically.)
    7.1.1 Size: 20.3  0.2 x 25.4  0.2 cm (nominal 8 x 10 in).
    7.1.2 Nominal exposed area: 406.5 cm\2\ (63 in\2\).
    7.1.3. Material: Glass fiber or other relatively inert, 
nonhygroscopic material. (8)
    7.1.4 Collection efficiency: 99 percent minimum as measured by the 
DOP test (ASTM-2986) for particles of 0.3 [micro]m diameter.
    7.1.5 Recommended pressure drop range: 42-54 mm Hg (5.6-7.2 kPa) at 
a flow rate of 1.5 std m\3\/min through the nominal exposed area.
    7.1.6 pH: 6 to 10. (11)
    7.1.7 Integrity: 2.4 mg maximum weight loss. (11)
    7.1.8 Pinholes: None.
    7.1.9 Tear strength: 500 g minimum for 20 mm wide strip cut from 
filter in weakest dimension. (See ASTM Test D828-60).
    7.1.10 Brittleness: No cracks or material separations after single 
lengthwise crease.
    7.2 Sampler. The air sampler shall provide means for drawing the air 
sample, via reduced pressure, through the filter at a uniform face 
velocity.
    7.2.1 The sampler shall have suitable means to:
    a. Hold and seal the filter to the sampler housing.
    b. Allow the filter to be changed conveniently.
    c. Preclude leaks that would cause error in the measurement of the 
air volume passing through the filter.
    d. ([dagger]) Manually adjust the flow rate to accommodate 
variations in filter pressure drop and site line voltage and altitude. 
The adjustment may be accomplished by an automatic flow controller or by 
a manual flow adjustment device. Any manual adjustment device must be 
designed with positive detents or other means to avoid unintentional 
changes in the setting.
---------------------------------------------------------------------------

    ([dagger]) See note at beginning of Section 7 of this appendix.
---------------------------------------------------------------------------

    7.2.2 Minimum sample flow rate, heavily loaded filter: 1.1 m\3\/min 
(39 ft\3\/min).[Dagger]
---------------------------------------------------------------------------

    [Dagger] These specifications are in actual air volume units; to 
convert to EPA standard air volume units, multiply the specifications by 
(Pb/Pstd)(298/T) where Pb and T are the 
barometric pressure in mm Hg (or kPa) and the temperature in K at the 
sampler, and Pstd is 760 mm Hg (or 101 kPa).
---------------------------------------------------------------------------

    7.2.3 Maximum sample flow rate, clean filter: 1.7 m\3\/min (60 
ft\3\/min).[Dagger]
    7.2.4 Blower Motor: The motor must be capable of continuous 
operation for 24-hr periods.
    7.3 Sampler shelter.
    7.3.1 The sampler shelter shall:
    a. Maintain the filter in a horizontal position at least 1 m above 
the sampler supporting surface so that sample air is drawn downward 
through the filter.
    b. Be rectangular in shape with a gabled roof, similar to the design 
shown in Figure 1.
    c. Cover and protect the filter and sampler from precipitation and 
other weather.
    d. Discharge exhaust air at least 40 cm from the sample air inlet.
    e. Be designed to minimize the collection of dust from the 
supporting surface by incorporating a baffle between the exhaust outlet 
and the supporting surface.
    7.3.2 The sampler cover or roof shall overhang the sampler housing 
somewhat, as shown in Figure 1, and shall be mounted so as to form an 
air inlet gap between the cover and the sampler housing walls. 
[dagger] This sample air inlet should be approximately 
uniform on all sides of the sampler. [dagger] The area of the 
sample air inlet must be sized to provide an effective particle capture 
air velocity of between 20 and 35 cm/sec at the recommended operational 
flow rate. The capture velocity is the sample air flow rate divided by 
the inlet area measured in a horizontal plane at the lower edge of the 
cover. [dagger] Ideally, the inlet area and operational flow 
rate should be selected to obtain a capture air velocity of 25 2 cm/sec.
    7.4 Flow rate measurement devices.
    7.4.1 The sampler shall incorporate a flow rate measurement device 
capable of indicating the total sampler flow rate. Two common types of 
flow indicators covered in the calibration procedure are (1) an 
electronic mass flowmeter and (2) an orifice or orifices

[[Page 31]]

located in the sample air stream together with a suitable pressure 
indicator such as a manometer, or aneroid pressure gauge. A pressure 
recorder may be used with an orifice to provide a continuous record of 
the flow. Other types of flow indicators (including rotameters) having 
comparable precision and accuracy are also acceptable.
    7.4.2 [dagger] The flow rate measurement device must be capable of 
being calibrated and read in units corresponding to a flow rate which is 
readable to the nearest 0.02 std m\3\/min over the range 1.0 to 1.8 std 
m\3\/min.
    7.5 Thermometer, to indicate the approximate air temperature at the 
flow rate measurement orifice, when temperature corrections are used.
    7.5.1 Range: -40[deg] to +50 [deg]C (223-323 K).
    7.5.2 Resolution: 2 [deg]C (2 K).
    7.6 Barometer, to indicate barometric pressure at the flow rate 
measurement orifice, when pressure corrections are used.
    7.6.1 Range: 500 to 800 mm Hg (66-106 kPa).
    7.6.2 Resolution: 5 mm Hg (0.67 kPa).
    7.7 Timing/control device.
    7.7.1 The timing device must be capable of starting and stopping the 
sampler to obtain an elapsed run-time of 24 hr 1 
hr (1,440 60 min).
    7.7.2 Accuracy of time setting: 30 min, or 
better. (See Section 6.8).
    7.8 Flow rate transfer standard, traceable to a primary standard. 
(See Section 9.2.)
    7.8.1 Approximate range: 1.0 to 1.8 m\3\/min.
    7.8.2 Resolution: 0.02 m\3\/min.
    7.8.3 Reproducibility: 2 percent (2 times 
coefficient of variation) over normal ranges of ambient temperature and 
pressure for the stated flow rate range. (See Reference 2, Section 2.)
    7.8.4 Maximum pressure drop at 1.7 std m\3\/min; 50 cm H2 
O (5 kPa).
    7.8.5 The flow rate transfer standard must connect without leaks to 
the inlet of the sampler and measure the flow rate of the total air 
sample.
    7.8.6 The flow rate transfer standard must include a means to vary 
the sampler flow rate over the range of 1.0 to 1.8 m\3\/min (35-64 
ft\3\/min) by introducing various levels of flow resistance between the 
sampler and the transfer standard inlet.
    7.8.7 The conventional type of flow transfer standard consists of: 
An orifice unit with adapter that connects to the inlet of the sampler, 
a manometer or other device to measure orifice pressure drop, a means to 
vary the flow through the sampler unit, a thermometer to measure the 
ambient temperature, and a barometer to measure ambient pressure. Two 
such devices are shown in Figures 2a and 2b. Figure 2a shows multiple 
fixed resistance plates, which necessitate disassembly of the unit each 
time the flow resistance is changed. A preferable design, illustrated in 
Figure 2b, has a variable flow restriction that can be adjusted 
externally without disassembly of the unit. Use of a conventional, 
orifice-type transfer standard is assumed in the calibration procedure 
(Section 9). However, the use of other types of transfer standards 
meeting the above specifications, such as the one shown in Figure 2c, 
may be approved; see the note following Section 9.1.
    7.9 Filter conditioning environment
    7.9.1 Controlled temperature: between 15[deg] and 30 [deg]C with 
less than 3 [deg]C variation during equilibration 
period.
    7.9.2 Controlled humidity: Less than 50 percent relative humidity, 
constant within 5 percent.
    7.10 Analytical balance.
    7.10.1 Sensitivity: 0.1 mg.
    7.10.2 Weighing chamber designed to accept an unfolded 20.3x25.4 cm 
(8x10 in) filter.
    7.11 Area light source, similar to X-ray film viewer, to backlight 
filters for visual inspection.
    7.12 Numbering device, capable of printing identification numbers on 
the filters before they are placed in the filter conditioning 
environment, if not numbered by the supplier.
    8.0 Procedure.
    (See References 1 and 2 for quality assurance information.)
    8.1 Number each filter, if not already numbered, near its edge with 
a unique identification number.
    8.2 Backlight each filter and inspect for pinholes, particles, and 
other imperfections; filters with visible imperfections must not be 
used.
    8.3 Equilibrate each filter in the conditioning environment for at 
least 24-hr.
    8.4 Following equilibration, weigh each filter to the nearest 
milligram and record this tare weight (Wi) with the filter 
identification number.
    8.5 Do not bend or fold the filter before collection of the sample.
    8.6 Open the shelter and install a numbered, preweighed filter in 
the sampler, following the sampler manufacturer's instructions. During 
inclement weather, precautions must be taken while changing filters to 
prevent damage to the clean filter and loss of sample from or damage to 
the exposed filter. Filter cassettes that can be loaded and unloaded in 
the laboratory may be used to minimize this problem (See Section 6.6).
    8.7 Close the shelter and run the sampler for at least 5 min to 
establish run-temperature conditions.
    8.8 Record the flow indicator reading and, if needed, the barometric 
pressure (P\3\3) and the ambient temperature 
(T\3\3) see NOTE following step 8.12). Stop the sampler. 
Determine the sampler flow rate (see Section 10.1); if it is outside the 
acceptable range (1.1 to 1.7 m\3\/min [39-60 ft\3\/min]), use a 
different filter, or adjust the sampler flow rate. Warning: Substantial 
flow adjustments may affect the

[[Page 32]]

calibration of the orifice-type flow indicators and may necessitate 
recalibration.
    8.9 Record the sampler identification information (filter number, 
site location or identification number, sample date, and starting time).
    8.10 Set the timer to start and stop the sampler such that the 
sampler runs 24-hrs, from midnight to midnight (local time).
    8.11 As soon as practical following the sampling period, run the 
sampler for at least 5 min to again establish run-temperature 
conditions.
    8.12 Record the flow indicator reading and, if needed, the 
barometric pressure (P\3\3) and the ambient temperature 
(T\3\3).

    Note: No onsite pressure or temperature measurements are necessary 
if the sampler flow indicator does not require pressure or temperature 
corrections (e.g., a mass flowmeter) or if average barometric pressure 
and seasonal average temperature for the site are incorporated into the 
sampler calibration (see step 9.3.9). For individual pressure and 
temperature corrections, the ambient pressure and temperature can be 
obtained by onsite measurements or from a nearby weather station. 
Barometric pressure readings obtained from airports must be station 
pressure, not corrected to sea level, and may need to be corrected for 
differences in elevation between the sampler site and the airport. For 
samplers having flow recorders but not constant flow controllers, the 
average temperature and pressure at the site during the sampling period 
should be estimated from weather bureau or other available data.

    8.13 Stop the sampler and carefully remove the filter, following the 
sampler manufacturer's instructions. Touch only the outer edges of the 
filter. See the precautions in step 8.6.
    8.14 Fold the filter in half lengthwise so that only surfaces with 
collected particulate matter are in contact and place it in the filter 
holder (glassine envelope or manila folder).
    8.15 Record the ending time or elapsed time on the filter 
information record, either from the stop set-point time, from an elapsed 
time indicator, or from a continuous flow record. The sample period must 
be 1,440 60 min. for a valid sample.
    8.16 Record on the filter information record any other factors, such 
as meteorological conditions, construction activity, fires or dust 
storms, etc., that might be pertinent to the measurement. If the sample 
is known to be defective, void it at this time.
    8.17 Equilibrate the exposed filter in the conditioning environment 
for at least 24-hrs.
    8.18 Immediately after equilibration, reweigh the filter to the 
nearest milligram and record the gross weight with the filter 
identification number. See Section 10 for TSP concentration 
calculations.
    9.0 Calibration.
    9.1 Calibration of the high volume sampler's flow indicating or 
control device is necessary to establish traceability of the field 
measurement to a primary standard via a flow rate transfer standard. 
Figure 3a illustrates the certification of the flow rate transfer 
standard and Figure 3b illustrates its use in calibrating a sampler flow 
indicator. Determination of the corrected flow rate from the sampler 
flow indicator, illustrated in Figure 3c, is addressed in Section 10.1

    Note: The following calibration procedure applies to a conventional 
orifice-type flow transfer standard and an orifice-type flow indicator 
in the sampler (the most common types). For samplers using a pressure 
recorder having a square-root scale, 3 other acceptable calibration 
procedures are provided in Reference 12. Other types of transfer 
standards may be used if the manufacturer or user provides an 
appropriately modified calibration procedure that has been approved by 
EPA under Section 2.8 of appendix C to part 58 of this chapter.

    9.2 Certification of the flow rate transfer standard.
    9.2.1 Equipment required: Positive displacement standard volume 
meter traceable to the National Bureau of Standards (such as a Roots 
meter or equivalent), stop-watch, manometer, thermometer, and barometer.
    9.2.2 Connect the flow rate transfer standard to the inlet of the 
standard volume meter. Connect the manometer to measure the pressure at 
the inlet of the standard volume meter. Connect the orifice manometer to 
the pressure tap on the transfer standard. Connect a high-volume air 
pump (such as a high-volume sampler blower) to the outlet side of the 
standard volume meter. See Figure 3a.
    9.2.3 Check for leaks by temporarily clamping both manometer lines 
(to avoid fluid loss) and blocking the orifice with a large-diameter 
rubber stopper, wide cellophane tape, or other suitable means. Start the 
high-volume air pump and note any change in the standard volume meter 
reading. The reading should remain constant. If the reading changes, 
locate any leaks by listening for a whistling sound and/or retightening 
all connections, making sure that all gaskets are properly installed.
    9.2.4 After satisfactorily completing the leak check as described 
above, unclamp both manometer lines and zero both manometers.
    9.2.5 Achieve the appropriate flow rate through the system, either 
by means of the variable flow resistance in the transfer standard or by 
varying the voltage to the air pump. (Use of resistance plates as shown 
in Figure 1a is discouraged because the above leak check must be 
repeated each time a new resistance plate is installed.) At least five

[[Page 33]]

different but constant flow rates, evenly distributed, with at least 
three in the specified flow rate interval (1.1 to 1.7 m\3\/min [39-60 
ft\3\/min]), are required.
    9.2.6 Measure and record the certification data on a form similar to 
the one illustrated in Figure 4 according to the following steps.
    9.2.7 Observe the barometric pressure and record as P1 
(item 8 in Figure 4).
    9.2.8 Read the ambient temperature in the vicinity of the standard 
volume meter and record it as T1 (item 9 in Figure 4).
    9.2.9 Start the blower motor, adjust the flow, and allow the system 
to run for at least 1 min for a constant motor speed to be attained.
    9.2.10 Observe the standard volume meter reading and simultaneously 
start a stopwatch. Record the initial meter reading (Vi) in 
column 1 of Figure 4.
    9.2.11 Maintain this constant flow rate until at least 3 m\3\ of air 
have passed through the standard volume meter. Record the standard 
volume meter inlet pressure manometer reading as [Delta]P (column 5 in 
Figure 4), and the orifice manometer reading as [Delta]H (column 7 in 
Figure 4). Be sure to indicate the correct units of measurement.
    9.2.12 After at least 3 m\3\ of air have passed through the system, 
observe the standard volume meter reading while simultaneously stopping 
the stopwatch. Record the final meter reading (Vf) in column 
2 and the elapsed time (t) in column 3 of Figure 4.
    9.2.13 Calculate the volume measured by the standard volume meter at 
meter conditions of temperature and pressures as 
Vm=Vf-Vi. Record in column 4 of Figure 
4.
    9.2.14 Correct this volume to standard volume (std m\3\) as follows:
    [GRAPHIC] [TIFF OMITTED] TR31AU93.024
    
where:

Vstd = standard volume, std m\3\;
Vm = actual volume measured by the standard volume meter;
P1 = barometric pressure during calibration, mm Hg or kPa;
[Delta]P = differential pressure at inlet to volume meter, mm Hg or kPa;
Pstd = 760 mm Hg or 101 kPa;
Tstd = 298 K;
T1 = ambient temperature during calibration, K.
Calculate the standard flow rate (std m\3\/min) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.013

where:

Qstd = standard volumetric flow rate, std m\3\/min
t = elapsed time, minutes.

    Record Qstd to the nearest 0.01 std m\3\/min in column 6 
of Figure 4.
    9.2.15 Repeat steps 9.2.9 through 9.2.14 for at least four 
additional constant flow rates, evenly spaced over the approximate range 
of 1.0 to 1.8 std m\3\/min (35-64 ft\3\/min).
    9.2.16 For each flow, compute

[radic][Delta][Delta]H (P1/Pstd)(298/
T1)

(column 7a of Figure 4) and plot these value against Qstd as 
shown in Figure 3a. Be sure to use consistent units (mm Hg or kPa) for 
barometric pressure. Draw the orifice transfer standard certification 
curve or calculate the linear least squares slope (m) and intercept (b) 
of the certification curve:

[radic][Delta][Delta]H (P1/Pstd)(298/
T1)

=mQstd+b. See Figures 3 and 4. A certification graph should 
be readable to 0.02 std m\3\/min.
    9.2.17 Recalibrate the transfer standard annually or as required by 
applicable quality control procedures. (See Reference 2.)
    9.3 Calibration of sampler flow indicator.

    Note: For samplers equipped with a flow controlling device, the flow 
controller must be disabled to allow flow changes during calibration of 
the sampler's flow indicator, or the alternate calibration of the flow 
controller given in 9.4 may be used. For samplers using an orifice-type 
flow indicator downstream of the motor, do not vary the flow rate by 
adjusting the voltage or power supplied to the sampler.

    9.3.1 A form similar to the one illustrated in Figure 5 should be 
used to record the calibration data.
    9.3.2 Connect the transfer standard to the inlet of the sampler. 
Connect the orifice manometer to the orifice pressure tap, as 
illustrated in Figure 3b. Make sure there are no leaks between the 
orifice unit and the sampler.
    9.3.3 Operate the sampler for at least 5 minutes to establish 
thermal equilibrium prior to the calibration.
    9.3.4 Measure and record the ambient temperature, T2, and 
the barometric pressure, P2, during calibration.
    9.3.5 Adjust the variable resistance or, if applicable, insert the 
appropriate resistance plate (or no plate) to achieve the desired flow 
rate.
    9.3.6 Let the sampler run for at least 2 min to re-establish the 
run-temperature conditions. Read and record the pressure drop across the 
orifice ([Delta]H) and the sampler flow rate indication (I) in the 
appropriate columns of Figure 5.
    9.3.7 Calculate [radic][Delta][Delta]H(P2/
Pstd)(298/T2) and determine the flow rate at 
standard conditions (Qstd) either graphically from the 
certification curve or by calculating Qstd from the least 
square slope and intercept of the transfer standard's transposed 
certification curve: Qstd=1/m [radic][Delta]H(P2/
Pstd)(298/T2)-b. Record the value of 
Qstd on Figure 5.

[[Page 34]]

    9.3.8 Repeat steps 9.3.5, 9.3.6, and 9.3.7 for several additional 
flow rates distributed over a range that includes 1.1 to 1.7 std m\3\/
min.
    9.3.9 Determine the calibration curve by plotting values of the 
appropriate expression involving I, selected from table 1, against 
Qstd. The choice of expression from table 1 depends on the 
flow rate measurement device used (see Section 7.4.1) and also on 
whether the calibration curve is to incorporate geographic average 
barometric pressure (Pa) and seasonal average temperature 
(Ta) for the site to approximate actual pressure and 
temperature. Where Pa and Ta can be determined for 
a site for a seasonal period such that the actual barometric pressure 
and temperature at the site do not vary by more than 60 mm Hg (8 kPa) from Pa or 15 [deg]C from Ta, respectively, then using 
Pa and Ta avoids the need for subsequent pressure 
and temperature calculation when the sampler is used. The geographic 
average barometric pressure (Pa) may be estimated from an 
altitude-pressure table or by making an (approximate) elevation 
correction of -26 mm Hg (-3.46 kPa) for each 305 m (1,000 ft) above sea 
level (760 mm Hg or 101 kPa). The seasonal average temperature 
(Ta) may be estimated from weather station or other records. 
Be sure to use consistent units (mm Hg or kPa) for barometric pressure.
    9.3.10 Draw the sampler calibration curve or calculate the linear 
least squares slope (m), intercept (b), and correlation coefficient of 
the calibration curve: [Expression from table 1]= mQstd+b. 
See Figures 3 and 5. Calibration curves should be readable to 0.02 std 
m\3\/min.
    9.3.11 For a sampler equipped with a flow controller, the flow 
controlling mechanism should be re-enabled and set to a flow near the 
lower flow limit to allow maximum control range. The sample flow rate 
should be verified at this time with a clean filter installed. Then add 
two or more filters to the sampler to see if the flow controller 
maintains a constant flow; this is particularly important at high 
altitudes where the range of the flow controller may be reduced.
    9.4 Alternate calibration of flow-controlled samplers. A flow-
controlled sampler may be calibrated solely at its controlled flow rate, 
provided that previous operating history of the sampler demonstrates 
that the flow rate is stable and reliable. In this case, the flow 
indicator may remain uncalibrated but should be used to indicate any 
relative change between initial and final flows, and the sampler should 
be recalibrated more often to minimize potential loss of samples because 
of controller malfunction.
    9.4.1 Set the flow controller for a flow near the lower limit of the 
flow range to allow maximum control range.
    9.4.2 Install a clean filter in the sampler and carry out steps 
9.3.2, 9.3.3, 9.3.4, 9.3.6, and 9.3.7.
    9.4.3 Following calibration, add one or two additional clean filters 
to the sampler, reconnect the transfer standard, and operate the sampler 
to verify that the controller maintains the same calibrated flow rate; 
this is particularly important at high altitudes where the flow control 
range may be reduced.



[[Page 35]]




    10.0 Calculations of TSP Concentration.
    10.1 Determine the average sampler flow rate during the sampling 
period according to either 10.1.1 or 10.1.2 below.
    10.1.1 For a sampler without a continuous flow recorder, determine 
the appropriate expression to be used from table 2 corresponding to the 
one from table 1 used in step 9.3.9. Using this appropriate expression, 
determine Qstd for the initial flow rate from the sampler 
calibration curve, either graphically or from the transposed regression 
equation:

Qstd =
1/m ([Appropriate expression from table 2]-b)

Similarly, determine Qstd from the final flow reading, and 
calculate the average flow Qstd as one-half the sum of the 
initial and final flow rates.
    10.1.2 For a sampler with a continuous flow recorder, determine the 
average flow rate device reading, I, for the period. Determine the 
appropriate expression from table 2 corresponding to the one from table 
1 used in step 9.3.9. Then using this expression and the average flow 
rate reading, determine Qstd from the sampler calibration 
curve, either graphically or from the transposed regression equation:

Qstd =

1/m ([Appropriate expression from table 2]-b)
    If the trace shows substantial flow change during the sampling 
period, greater accuracy may be achieved by dividing the sampling period 
into intervals and calculating an average reading before determining 
Qstd.
    10.2 Calculate the total air volume sampled as:

V-Qstdx t

where:

V = total air volume sampled, in standard volume units, std m\3\/;
Qstd = average standard flow rate, std m\3\/min;
t = sampling time, min.

    10.3 Calculate and report the particulate matter concentration as:
    [GRAPHIC] [TIFF OMITTED] TR31AU93.025
    
where:

TSP = mass concentration of total suspended particulate matter, 
[micro]g/std m\3\;
Wi = initial weight of clean filter, g;
Wf = final weight of exposed filter, g;
V = air volume sampled, converted to standard conditions, std m\3\,
10\6\ = conversion of g to [micro]g.

    10.4 If desired, the actual particulate matter concentration (see 
Section 2.2) can be calculated as follows:

(TSP)a=TSP (P3/Pstd)(298/T3)

where:

(TSP)a = actual concentration at field conditions, [micro]g/
m\3\;

[[Page 36]]

TSP = concentration at standard conditions, [micro]g/std m\3\;
P3 = average barometric pressure during sampling period, mm 
Hg;
Pstd = 760 mn Hg (or 101 kPa);
T3 = average ambient temperature during sampling period, K.

    11.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1976.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 1977.
    3. Wedding, J. B., A. R. McFarland, and J. E. Cernak. Large Particle 
Collection Characteristics of Ambient Aerosol Samplers. Environ. Sci. 
Technol. 11:387-390, 1977.
    4. McKee, H. C., et al. Collaborative Testing of Methods to Measure 
Air Pollutants, I. The High-Volume Method for Suspended Particulate 
Matter. J. Air Poll. Cont. Assoc., 22 (342), 1972.
    5. Clement, R. E., and F. W. Karasek. Sample Composition Changes in 
Sampling and Analysis of Organic Compounds in Aerosols. The Intern. J. 
Environ. Anal. Chem., 7:109, 1979.
    6. Lee, R. E., Jr., and J. Wagman. A Sampling Anomaly in the 
Determination of Atmospheric Sulfuric Concentration. Am. Ind. Hygiene 
Assoc. J., 27:266, 1966.
    7. Appel, B. R., et al. Interference Effects in Sampling Particulate 
Nitrate in Ambient Air. Atmospheric Environment, 13:319, 1979.
    8. Tierney, G. P., and W. D. Conner. Hygroscopic Effects on Weight 
Determinations of Particulates Collected on Glass-Fiber Filters. Am. 
Ind. Hygiene Assoc. J., 28:363, 1967.
    9. Chahal, H. S., and D. J. Romano. High-Volume Sampling Effect of 
Windborne Particulate Matter Deposited During Idle Periods. J. Air Poll. 
Cont. Assoc., Vol. 26 (885), 1976.
    10. Patterson, R. K. Aerosol Contamination from High-Volume Sampler 
Exhaust. J. Air Poll. Cont. Assoc., Vol. 30 (169), 1980.
    11. EPA Test Procedures for Determining pH and Integrity of High-
Volume Air Filters. QAD/M-80.01. Available from the Methods 
Standardization Branch, Quality Assurance Division, Environmental 
Monitoring Systems Laboratory (MD-77), U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1980.
    12. Smith, F., P. S. Wohlschlegel, R. S. C. Rogers, and D. J. 
Mulligan. Investigation of Flow Rate Calibration Procedures Associated 
with the High-Volume Method for Determination of Suspended Particulates. 
EPA-600/4-78-047, U.S. Environmental Protection Agency, Research 
Triangle Park, NC, June 1978.



[[Page 37]]





[[Page 38]]





[[Page 39]]





[[Page 40]]





[47 FR 54912, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]



   Sec. Appendix C to Part 50--Measurement Principle and Calibration 
Procedure for the Measurement of Carbon Monoxide in the Atmosphere (Non-
                     Dispersive Infrared Photometry)

                          Measurement Principle

    1. Measurements are based on the absorption of infrared radiation by 
carbon monoxide (CO) in a non-dispersive photometer. Infrared energy 
from a source is passed through a cell containing the gas sample to be 
analyzed, and the quantitative absorption of energy by CO in the sample 
cell is measured by a suitable detector. The photometer is sensitized to 
CO by employing CO gas in either the detector or in a filter cell in the 
optical path, thereby limiting the measured absorption to one or more of 
the characteristic wavelengths at which CO strongly absorbs. Optical 
filters or other means may

[[Page 41]]

also be used to limit sensitivity of the photometer to a narrow band of 
interest. Various schemes may be used to provide a suitable zero 
reference for the photometer. The measured absorption is converted to an 
electrical output signal, which is related to the concentration of CO in 
the measurement cell.
    2. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter.
    3. Sampling considerations.
    The use of a particle filter on the sample inlet line of an NDIR CO 
analyzer is optional and left to the discretion of the user or the 
manufacturer. Use of filter should depend on the analyzer's 
susceptibility to interference, malfunction, or damage due to particles.

                          Calibration Procedure

    1. Principle. Either of two methods may be used for dynamic 
multipoint calibration of CO analyzers:
    (1) One method uses a single certified standard cylinder of CO, 
diluted as necessary with zero air, to obtain the various calibration 
concentrations needed.
    (2) The other method uses individual certified standard cylinders of 
CO for each concentration needed. Additional information on calibration 
may be found in Section 2.0.9 of Reference 1.
    2. Apparatus. The major components and typical configurations of the 
calibration systems for the two calibration methods are shown in Figures 
1 and 2.
    2.1 Flow controller(s). Device capable of adjusting and regulating 
flow rates. Flow rates for the dilution method (Figure 1) must be 
regulated to 1%.
    2.2 Flow meter(s). Calibrated flow meter capable of measuring and 
monitoring flow rates. Flow rates for the dilution method (Figure 1) 
must be measured with an accuracy of 2% of the 
measured value.
    2.3 Pressure regulator(s) for standard CO cylinder(s). Regulator 
must have nonreactive diaphragm and internal parts and a suitable 
delivery pressure.
    2.4 Mixing chamber. A chamber designed to provide thorough mixing of 
CO and diluent air for the dilution method.
    2.5 Output manifold. The output manifold should be of sufficient 
diameter to insure an insignificant pressure drop at the analyzer 
connection. The system must have a vent designed to insure atmospheric 
pressure at the manifold and to prevent ambient air from entering the 
manifold.
    3. Reagents.
    3.1 CO concentration standard(s). Cylinder(s) of CO in air 
containing appropriate concentrations(s) of CO suitable for the selected 
operating range of the analyzer under calibration; CO standards for the 
dilution method may be contained in a nitrogen matrix if the zero air 
dilution ratio is not less than 100:1. The assay of the cylinder(s) must 
be traceable either to a National Bureau of Standards (NBS) CO in air 
Standard Reference Material (SRM) or to an NBS/EPA-approved commercially 
available Certified Reference Material (CRM). CRM's are described in 
Reference 2, and a list of CRM sources is available from the address 
shown for Reference 2. A recommended protocol for certifying CO gas 
cylinders against either a CO SRM or a CRM is given in Reference 1. CO 
gas cylinders should be recertified on a regular basis as determined by 
the local quality control program.
    3.2 Dilution gas (zero air). Air, free of contaminants which will 
cause a detectable response on the CO analyzer. The zero air should 
contain <0.1 ppm CO. A procedure for generating zero air is given in 
Reference 1.
    4. Procedure Using Dynamic Dilution Method.
    4.1 Assemble a dynamic calibration system such as the one shown in 
Figure 1. All calibration gases including zero air must be introduced 
into the sample inlet of the analyzer system. For specific operating 
instructions refer to the manufacturer's manual.
    4.2 Insure that all flowmeters are properly calibrated, under the 
conditions of use, if appropriate, against an authoritative standard 
such as a soap-bubble meter or wet-test meter. All volumetric flowrates 
should be corrected to 25 [deg]C and 760 mm Hg (101 kPa). A discussion 
on calibration of flowmeters is given in Reference 1.
    4.3 Select the operating range of the CO analyzer to be calibrated.
    4.4 Connect the signal output of the CO analyzer to the input of the 
strip chart recorder or other data collection device. All adjustments to 
the analyzer should be based on the appropriate strip chart or data 
device readings. References to analyzer responses in the procedure given 
below refer to recorder or data device responses.
    4.5 Adjust the calibration system to deliver zero air to the output 
manifold. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is pulled into the manifold vent. Allow the analyzer to sample zero 
air until a stable respose is obtained. After the response has 
stabilized, adjust the analyzer zero control. Offsetting the analyzer 
zero adjustments to +5 percent of scale is recommended to facilitate 
observing negative zero drift. Record the stable zero air response as 
ZCO.
    4.6 Adjust the zero air flow and the CO flow from the standard CO 
cylinder to provide a diluted CO concentration of approximately 80 
percent of the upper range limit (URL) of the operating range of the 
analyzer. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is

[[Page 42]]

pulled into the manifold vent. The exact CO concentration is calculated 
from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.026

where:

[CO]OUT = diluted CO concentration at the output manifold, 
ppm;
[CO]STD = concentration of the undiluted CO standard, ppm;
FCO = flow rate of the CO standard corrected to 25 [deg]C and 
760 mm Hg, (101 kPa), L/min; and
FD = flow rate of the dilution air corrected to 25 [deg]C and 
760 mm Hg, (101 kPa), L/min.

    Sample this CO concentration until a stable response is obtained. 
Adjust the analyzer span control to obtain a recorder response as 
indicated below:

Recorder response (percent scale) =

[GRAPHIC] [TIFF OMITTED] TR31AU93.027

where:

URL = nominal upper range limit of the analyzer's operating range, and
ZCO = analyzer response to zero air, % scale.

    If substantial adjustment of the analyzer span control is required, 
it may be necessary to recheck the zero and span adjustments by 
repeating Steps 4.5 and 4.6. Record the CO concentration and the 
analyzer's response. 4.7 Generate several additional concentrations (at 
least three evenly spaced points across the remaining scale are 
suggested to verify linearity) by decreasing FCO or 
increasing FD. Be sure the total flow exceeds the analyzer's 
total flow demand. For each concentration generated, calculate the exact 
CO concentration using Equation (1). Record the concentration and the 
analyzer's response for each concentration. Plot the analyzer responses 
versus the corresponding CO concentrations and draw or calculate the 
calibration curve.
    5. Procedure Using Multiple Cylinder Method. Use the procedure for 
the dynamic dilution method with the following changes:
    5.1 Use a multi-cylinder system such as the typical one shown in 
Figure 2.
    5.2 The flowmeter need not be accurately calibrated, provided the 
flow in the output manifold exceeds the analyzer's flow demand.
    5.3 The various CO calibration concentrations required in Steps 4.6 
and 4.7 are obtained without dilution by selecting the appropriate 
certified standard cylinder.

                               References

    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II--Ambient Air Specific Methods, EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Environmental Monitoring Systems 
Laboratory, Research Triangle Park, NC 27711, 1977.
    2. A procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, U.S. Environmental Protection Agency, Environmental 
Monitoring Systems Laboratory (MD-77), Research Triangle Park, NC 27711, 
January 1981.

[[Page 43]]




[[Page 44]]





[47 FR 54922, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]

[[Page 45]]



   Sec. Appendix D to Part 50--Measurement Principle and Calibration 
        Procedure for the Measurement of Ozone in the Atmosphere

                          Measurement Principle

    1. Ambient air and ethylene are delivered simultaneously to a mixing 
zone where the ozone in the air reacts with the ethylene to emit light, 
which is detected by a photomultiplier tube. The resulting photocurrent 
is amplified and is either read directly or displayed on a recorder.
    2. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter and calibrated as follows:

                          Calibration Procedure

    1. Principle. The calibration procedure is based on the photometric 
assay of ozone (O3) concentrations in a dynamic flow system. 
The concentration of O3 in an absorption cell is determined 
from a measurement of the amount of 254 nm light absorbed by the sample. 
This determination requires knowledge of (1) the absorption coefficient 
([alpha]) of O3 at 254 nm, (2) the optical path length (l) 
through the sample, (3) the transmittance of the sample at a wavelength 
of 254 nm, and (4) the temperature (T) and pressure (P) of the sample. 
The transmittance is defined as the ratio I/I0, where I is 
the intensity of light which passes through the cell and is sensed by 
the detector when the cell contains an O3 sample, and 
I0 is the intensity of light which passes through the cell 
and is sensed by the detector when the cell contains zero air. It is 
assumed that all conditions of the system, except for the contents of 
the absorption cell, are identical during measurement of I and 
I0. The quantities defined above are related by the Beer-
Lambert absorption law,
[GRAPHIC] [TIFF OMITTED] TR31AU93.028

where:

[alpha] = absorption coefficient of O3 at 254 nm=308 4 atm-1 cm-1 at 0 [deg]C and 760 
torr.\3\(1, 2, 3, 4, 5, 6, 7)
c = O3 concentration in atmospheres
l = optical path length in cm

    In practice, a stable O3 generator is used to produce 
O3 concentrations over the required range. Each O3 
concentration is determined from the measurement of the transmittance 
(I/I0) of the sample at 254 nm with a photometer of path 
length l and calculated from the equation,
[GRAPHIC] [TIFF OMITTED] TR31AU93.029

The calculated O3 concentrations must be corrected for 
O3 losses which may occur in the photometer and for the 
temperature and pressure of the sample.
    2. Applicability. This procedure is applicable to the calibration of 
ambient air O3 analyzers, either directly or by means of a 
transfer standard certified by this procedure. Transfer standards must 
meet the requirements and specifications set forth in Reference 8.
    3. Apparatus. A complete UV calibration system consists of an ozone 
generator, an output port or manifold, a photometer, an appropriate 
source of zero air, and other components as necessary. The configuration 
must provide a stable ozone concentration at the system output and allow 
the photometer to accurately assay the output concentration to the 
precision specified for the photometer (3.1). Figure 1 shows a commonly 
used configuration and serves to illustrate the calibration procedure 
which follows. Other configurations may require appropriate variations 
in the procedural steps. All connections between components in the 
calibration system downstream of the O3 generator should be 
of glass, Teflon, or other relatively inert materials. Additional 
information regarding the assembly of a UV photometric calibration 
apparatus is given in Reference 9. For certification of transfer 
standards which provide their own source of O3, the transfer 
standard may replace the O3 generator and possibly other 
components shown in Figure 1; see Reference 8 for guidance.
    3.1 UV photometer. The photometer consists of a low-pressure mercury 
discharge lamp, (optional) collimation optics, an absorption cell, a 
detector, and signal-processing electronics, as illustrated in Figure 1. 
It must be capable of measuring the transmittance, I/I0, at a 
wavelength of 254 nm with sufficient precision such that the standard 
deviation of the concentration measurements does not exceed the greater 
of 0.005 ppm or 3% of the concentration. Because the low-pressure 
mercury lamp radiates at several wavelengths, the photometer must 
incorporate suitable means to assure that no O3 is generated 
in the cell by the lamp, and that at least 99.5% of the radiation sensed 
by the detector is 254 nm radiation. (This can be readily achieved by 
prudent selection of optical filter and detector response 
characteristics.) The length of the light path through the absorption 
cell must be known with an accuracy of at least 99.5%. In addition, the 
cell and associated plumbing must be designed to

[[Page 46]]

minimize loss of O3 from contact with cell walls and gas 
handling components. See Reference 9 for additional information.
    3.2 Air flow controllers. Devices capable of regulating air flows as 
necessary to meet the output stability and photometer precision 
requirements.
    3.3 Ozone generator. Device capable of generating stable levels of 
O3 over the required concentration range.
    3.4 Output manifold. The output manifold should be constructed of 
glass, Teflon, or other relatively inert material, and should be of 
sufficient diameter to insure a negligible pressure drop at the 
photometer connection and other output ports. The system must have a 
vent designed to insure atmospheric pressure in the manifold and to 
prevent ambient air from entering the manifold.
    3.5 Two-way valve. Manual or automatic valve, or other means to 
switch the photometer flow between zero air and the O3 
concentration.
    3.6 Temperature indicator. Accurate to 1 
[deg]C.
    3.7 Barometer or pressure indicator. Accurate to 2 torr.
    4. Reagents.
    4.1 Zero air. The zero air must be free of contaminants which would 
cause a detectable response from the O3 analyzer, and it 
should be free of NO, C2 H4, and other species 
which react with O3. A procedure for generating suitable zero 
air is given in Reference 9. As shown in Figure 1, the zero air supplied 
to the photometer cell for the I0 reference measurement must 
be derived from the same source as the zero air used for generation of 
the ozone concentration to be assayed (I measurement). When using the 
photometer to certify a transfer standard having its own source of 
ozone, see Reference 8 for guidance on meeting this requirement.
    5. Procedure.
    5.1 General operation. The calibration photometer must be dedicated 
exclusively to use as a calibration standard. It should always be used 
with clean, filtered calibration gases, and never used for ambient air 
sampling. Consideration should be given to locating the calibration 
photometer in a clean laboratory where it can be stationary, protected 
from physical shock, operated by a responsible analyst, and used as a 
common standard for all field calibrations via transfer standards.
    5.2 Preparation. Proper operation of the photometer is of critical 
importance to the accuracy of this procedure. The following steps will 
help to verify proper operation. The steps are not necessarily required 
prior to each use of the photometer. Upon initial operation of the 
photometer, these steps should be carried out frequently, with all 
quantitative results or indications recorded in a chronological record 
either in tabular form or plotted on a graphical chart. As the 
performance and stability record of the photometer is established, the 
frequency of these steps may be reduced consistent with the documented 
stability of the photometer.
    5.2.1 Instruction manual: Carry out all set up and adjustment 
procedures or checks as described in the operation or instruction manual 
associated with the photometer.
    5.2.2 System check: Check the photometer system for integrity, 
leaks, cleanliness, proper flowrates, etc. Service or replace filters 
and zero air scrubbers or other consumable materials, as necessary.
    5.2.3 Linearity: Verify that the photometer manufacturer has 
adequately established that the linearity error of the photometer is 
less than 3%, or test the linearity by dilution as follows: Generate and 
assay an O3 concentration near the upper range limit of the 
system (0.5 or 1.0 ppm), then accurately dilute that concentration with 
zero air and reassay it. Repeat at several different dilution ratios. 
Compare the assay of the original concentration with the assay of the 
diluted concentration divided by the dilution ratio, as follows
[GRAPHIC] [TIFF OMITTED] TR31AU93.030

where:

E = linearity error, percent
A1 = assay of the original concentration
A2 = assay of the diluted concentration
R = dilution ratio = flow of original concentration divided by the total 
flow

    The linearity error must be less than 5%. Since the accuracy of the 
measured flow-rates will affect the linearity error as measured this 
way, the test is not necessarily conclusive. Additional information on 
verifying linearity is contained in Reference 9.
    5.2.4 Intercomparison: When possible, the photometer should be 
occasionally intercompared, either directly or via transfer standards, 
with calibration photometers used by other agencies or laboratories.
    5.2.5 Ozone losses: Some portion of the O3 may be lost 
upon contact with the photometer cell walls and gas handling components. 
The magnitude of this loss must be determined and used to correct the 
calculated O3 concentration. This loss must not exceed 5%. 
Some guidelines for quantitatively determining this loss are discussed 
in Reference 9.
    5.3 Assay of O3 concentrations.
    5.3.1 Allow the photometer system to warm up and stabilizer.
    5.3.2 Verify that the flowrate through the photometer absorption 
cell, F allows the cell to be flushed in a reasonably short period of 
time (2 liter/min is a typical flow). The precision of the measurements 
is inversely related to the time required for flushing, since the 
photometer drift error increases with time.

[[Page 47]]

    5.3.3 Insure that the flowrate into the output manifold is at least 
1 liter/min greater than the total flowrate required by the photometer 
and any other flow demand connected to the manifold.
    5.3.4 Insure that the flowrate of zero air, Fz, is at 
least 1 liter/min greater than the flowrate required by the photometer.
    5.3.5 With zero air flowing in the output manifold, actuate the two-
way valve to allow the photometer to sample first the manifold zero air, 
then Fz. The two photometer readings must be equal 
(I=Io).

    Note: In some commercially available photometers, the operation of 
the two-way valve and various other operations in section 5.3 may be 
carried out automatically by the photometer.

    5.3.6 Adjust the O3 generator to produce an O3 
concentration as needed.
    5.3.7 Actuate the two-way valve to allow the photometer to sample 
zero air until the absorption cell is thoroughly flushed and record the 
stable measured value of Io.
    5.3.8 Actuate the two-way valve to allow the photometer to sample 
the ozone concentration until the absorption cell is thoroughly flushed 
and record the stable measured value of I.
    5.3.9 Record the temperature and pressure of the sample in the 
photometer absorption cell. (See Reference 9 for guidance.)
    5.3.10 Calculate the O3 concentration from equation 4. An 
average of several determinations will provide better precision.
[GRAPHIC] [TIFF OMITTED] TR31AU93.032

where:

[O3]OUT = O3 concentration, ppm
[alpha] = absorption coefficient of O3 at 254 nm=308 
atm-1 cm-1 at 0 [deg]C and 760 torr
l = optical path length, cm
T = sample temperature, K
P = sample pressure, torr
L = correction factor for O3 losses from 5.2.5=(1-fraction 
O3 lost).

    Note: Some commercial photometers may automatically evaluate all or 
part of equation 4. It is the operator's responsibility to verify that 
all of the information required for equation 4 is obtained, either 
automatically by the photometer or manually. For ``automatic'' 
photometers which evaluate the first term of equation 4 based on a 
linear approximation, a manual correction may be required, particularly 
at higher O3 levels. See the photometer instruction manual 
and Reference 9 for guidance.

    5.3.11 Obtain additional O3 concentration standards as 
necessary by repeating steps 5.3.6 to 5.3.10 or by Option 1.
    5.4 Certification of transfer standards. A transfer standard is 
certified by relating the output of the transfer standard to one or more 
ozone standards as determined according to section 5.3. The exact 
procedure varies depending on the nature and design of the transfer 
standard. Consult Reference 8 for guidance.
    5.5 Calibration of ozone analyzers. Ozone analyzers are calibrated 
as follows, using ozone standards obtained directly according to section 
5.3 or by means of a certified transfer standard.
    5.5.1 Allow sufficient time for the O3 analyzer and the 
photometer or transfer standard to warmup and stabilize.
    5.5.2 Allow the O3 analyzer to sample zero air until a 
stable response is obtained and adjust the O3 analyzer's zero 
control. Offsetting the analyzer's zero adjustment to +5% of scale is 
recommended to facilitate observing negative zero drift. Record the 
stable zero air response as ``Z''.
    5.5.3 Generate an O3 concentration standard of 
approximately 80% of the desired upper range limit (URL) of the 
O3 analyzer. Allow the O3 analyzer to sample this 
O3 concentration standard until a stable response is 
obtained.
    5.5.4 Adjust the O3 analyzer's span control to obtain a 
convenient recorder response as indicated below:
    recorder response (%scale) =
    [GRAPHIC] [TIFF OMITTED] TR31AU93.033
    
where:

URL = upper range limit of the O3 analyzer, ppm
Z = recorder response with zero air, % scale

    Record the O3 concentration and the corresponding 
analyzer response. If substantial adjustment of the span control is 
necessary, recheck the zero and span adjustments by repeating steps 
5.5.2 to 5.5.4.
    5.5.5 Generate several other O3 concentration standards 
(at least 5 others are recommended) over the scale range of the 
O3 analyzer by adjusting the O3 source or by 
Option 1. For each O3 concentration standard, record the 
O3 and the corresponding analyzer response.
    5.5.6 Plot the O3 analyzer responses versus the 
corresponding O3 concentrations and draw the O3 
analyzer's calibration curve or calculate the appropriate response 
factor.
    5.5.7 Option 1: The various O3 concentrations required in 
steps 5.3.11 and 5.5.5 may be obtained by dilution of the O3 
concentration generated in steps 5.3.6 and 5.5.3. With this option, 
accurate flow measurements are required. The dynamic calibration system 
may be modified as shown in Figure 2 to allow for dilution air to be 
metered in downstream of the O3 generator. A mixing chamber 
between the O3 generator and the output manifold is also 
required. The flowrate through the O3 generator 
(Fo) and the dilution air flowrate

[[Page 48]]

(FD) are measured with a reliable flow or volume standard 
traceable to NBS. Each O3 concentration generated by dilution 
is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.031

where:

[O3]'OUT = diluted O3 concentration, 
ppm
F0 = flowrate through the O3 generator, liter/min
FD = diluent air flowrate, liter/min

                               References

    1. E.C.Y. Inn and Y. Tanaka, ``Absorption coefficient of Ozone in 
the Ultraviolet and Visible Regions'', J. Opt. Soc. Am., 43, 870 (1953).
    2. A. G. Hearn, ``Absorption of Ozone in the Ultraviolet and Visible 
Regions of the Spectrum'', Proc. Phys. Soc. (London), 78, 932 (1961).
    3. W. B. DeMore and O. Raper, ``Hartley Band Extinction Coefficients 
of Ozone in the Gas Phase and in Liquid Nitrogen, Carbon Monoxide, and 
Argon'', J. Phys. Chem., 68, 412 (1964).
    4. M. Griggs, ``Absorption Coefficients of Ozone in the Ultraviolet 
and Visible Regions'', J. Chem. Phys., 49, 857 (1968).
    5. K. H. Becker, U. Schurath, and H. Seitz, ``Ozone Olefin Reactions 
in the Gas Phase. 1. Rate Constants and Activation Energies'', Int'l 
Jour. of Chem. Kinetics, VI, 725 (1974).
    6. M. A. A. Clyne and J. A. Coxom, ``Kinetic Studies of Oxy-halogen 
Radical Systems'', Proc. Roy. Soc., A303, 207 (1968).
    7. J. W. Simons, R. J. Paur, H. A. Webster, and E. J. Bair, ``Ozone 
Ultraviolet Photolysis. VI. The Ultraviolet Spectrum'', J. Chem. Phys., 
59, 1203 (1973).
    8. Transfer Standards for Calibration of Ambient Air Monitoring 
Analyzers for Ozone, EPA publication number EPA-600/4-79-056, EPA, 
National Exposure Research Laboratory, Department E, (MD-77B), Research 
Triangle Park, NC 27711.
    9. Technical Assistance Document for the Calibration of Ambient 
Ozone Monitors, EPA publication number EPA-600/4-79-057, EPA, National 
Exposure Research Laboratory, Department E, (MD-77B), Research Triangle 
Park, NC 27711.

[[Page 49]]




[44 FR 8224, Feb. 8, 1979, as amended at 62 FR 38895, July 18, 1997]

[[Page 50]]



                  Sec. Appendix E to Part 50 [Reserved]



   Sec. Appendix F to Part 50--Measurement Principle and Calibration 
Procedure for the Measurement of Nitrogen Dioxide in the Atmosphere (Gas 
                        Phase Chemiluminescence)

                       Principle and Applicability

    1. Atmospheric concentrations of nitrogen dioxide (NO2) 
are measured indirectly by photometrically measuring the light 
intensity, at wavelengths greater than 600 nanometers, resulting from 
the chemiluminescent reaction of nitric oxide (NO) with ozone 
(O3). (1,2,3) NO2 is first quantitatively reduced 
to NO(4,5,6) by means of a converter. NO, which commonly exists in 
ambient air together with NO2, passes through the converter 
unchanged causing a resultant total NOX concentration equal 
to NO+NO2. A sample of the input air is also measured without 
having passed through the converted. This latter NO measurement is 
subtracted from the former measurement (NO+NO2) to yield the 
final NO2 measurement. The NO and NO+NO2 
measurements may be made concurrently with dual systems, or cyclically 
with the same system provided the cycle time does not exceed 1 minute.
    2. Sampling considerations.
    2.1 Chemiluminescence NO/NOX/NO2 analyzers 
will respond to other nitrogen containing compounds, such as 
peroxyacetyl nitrate (PAN), which might be reduced to NO in the thermal 
converter. (7) Atmospheric concentrations of these potential 
interferences are generally low relative to NO2 and valid 
NO2 measurements may be obtained. In certain geographical 
areas, where the concentration of these potential interferences is known 
or suspected to be high relative to NO2, the use of an 
equivalent method for the measurement of NO2 is recommended.
    2.2 The use of integrating flasks on the sample inlet line of 
chemiluminescence NO/NOX/NO2 analyzers is optional 
and left to couraged. The sample residence time between the sampling 
point and the analyzer should be kept to a minimum to avoid erroneous 
NO2 measurements resulting from the reaction of ambient 
levels of NO and O3 in the sampling system.
    2.3 The use of particulate filters on the sample inlet line of 
chemiluminescence NO/NOX/NO2 analyzers is optional 
and left to the discretion of the user or the manufacturer.
Use of the filter should depend on the analyzer's susceptibility to 
interference, malfunction, or damage due to particulates. Users are 
cautioned that particulate matter concentrated on a filter may cause 
erroneous NO2 measurements and therefore filters should be 
changed frequently.
    3. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter.

                               Calibration

    1. Alternative A--Gas phase titration (GPT) of an NO standard with 
O3.
    Major equipment required: Stable O3 generator. 
Chemiluminescence NO/NOX/NO2 analyzer with strip 
chart recorder(s). NO concentration standard.
    1.1 Principle. This calibration technique is based upon the rapid 
gas phase reaction between NO and O3 to produce 
stoichiometric quantities of NO2 in accordance with the 
following equation: (8)
[GRAPHIC] [TIFF OMITTED] TC08NO91.075

The quantitative nature of this reaction is such that when the NO 
concentration is known, the concentration of NO2 can be 
determined. Ozone is added to excess NO in a dynamic calibration system, 
and the NO channel of the chemiluminescence NO/NOX/
NO2 analyzer is used as an indicator of changes in NO 
concentration. Upon the addition of O3, the decrease in NO 
concentration observed on the calibrated NO channel is equivalent to the 
concentration of NO2 produced. The amount of NO2 
generated may be varied by adding variable amounts of O3 from 
a stable uncalibrated O3 generator. (9)
    1.2 Apparatus. Figure 1, a schematic of a typical GPT apparatus, 
shows the suggested configuration of the components listed below. All 
connections between components in the calibration system downstream from 
the O3 generator should be of glass, Teflon [reg], 
or other non-reactive material.
    1.2.1 Air flow controllers. Devices capable of maintaining constant 
air flows within 2% of the required flowrate.
    1.2.2 NO flow controller. A device capable of maintaining constant 
NO flows within 2% of the required flowrate. 
Component parts in contact with the NO should be of a non-reactive 
material.
    1.2.3 Air flowmeters. Calibrated flowmeters capable of measuring and 
monitoring air flowrates with an accuracy of 2% of 
the measured flowrate.
    1.2.4 NO flowmeter. A calibrated flowmeter capable of measuring and 
monitoring NO flowrates with an accuracy of 2% of 
the measured flowrate. (Rotameters have been reported to operate 
unreliably when measuring low NO flows and are not recommended.)
    1.2.5 Pressure regulator for standard NO cylinder. This regulator 
must have a nonreactive diaphragm and internal parts and a suitable 
delivery pressure.
    1.2.6 Ozone generator. The generator must be capable of generating 
sufficient and stable levels of O3 for reaction with NO to 
generate

[[Page 51]]

NO2 concentrations in the range required. Ozone generators of 
the electric discharge type may produce NO and NO2 and are 
not recommended.
    1.2.7 Valve. A valve may be used as shown in Figure 1 to divert the 
NO flow when zero air is required at the manifold. The valve should be 
constructed of glass, Teflon [reg], or other nonreactive 
material.
    1.2.8 Reaction chamber. A chamber, constructed of glass, Teflon 
[reg], or other nonreactive material, for the quantitative 
reaction of O3 with excess NO. The chamber should be of 
sufficient volume (VRC) such that the residence time (tR) 
meets the requirements specified in 1.4. For practical reasons, tR 
should be less than 2 minutes.
    1.2.9 Mixing chamber. A chamber constructed of glass, Teflon 
[reg], or other nonreactive material and designed to provide 
thorough mixing of reaction products and diluent air. The residence time 
is not critical when the dynamic parameter specification given in 1.4 is 
met.
    1.2.10 Output manifold. The output manifold should be constructed of 
glass, Teflon [reg], or other non-reactive material and 
should be of sufficient diameter to insure an insignificant pressure 
drop at the analyzer connection. The system must have a vent designed to 
insure atmospheric pressure at the manifold and to prevent ambient air 
from entering the manifold.
    1.3 Reagents.
    1.3.1 NO concentration standard. Gas cylinder standard containing 50 
to 100 ppm NO in N2 with less than 1 ppm NO2. This 
standard must be traceable to a National Bureau of Standards (NBS) NO in 
N2 Standard Reference Material (SRM 1683 or SRM 1684), an NBS 
NO2 Standard Reference Material (SRM 1629), or an NBS/EPA-
approved commercially available Certified Reference Material (CRM). 
CRM's are described in Reference 14, and a list of CRM sources is 
available from the address shown for Reference 14. A recommended 
protocol for certifying NO gas cylinders against either an NO SRM or CRM 
is given in section 2.0.7 of Reference 15. Reference 13 gives procedures 
for certifying an NO gas cylinder against an NBS NO2 SRM and 
for determining the amount of NO2 impurity in an NO cylinder.
    1.3.2 Zero air. Air, free of contaminants which will cause a 
detectable response on the NO/NOX/NO2 analyzer or 
which might react with either NO, O3, or NO2 in 
the gas phase titration. A procedure for generating zero air is given in 
reference 13.
    1.4 Dynamic parameter specification.
    1.4.1 The O3 generator air flowrate (F0) and 
NO flowrate (FNO) (see Figure 1) must be adjusted such that 
the following relationship holds:
[GRAPHIC] [TIFF OMITTED] TC08NO91.076

[GRAPHIC] [TIFF OMITTED] TC08NO91.077

[GRAPHIC] [TIFF OMITTED] TC08NO91.078

where:

PR = dynamic parameter specification, determined empirically, to insure 
complete reaction of the available O3, ppm-minute
[NO]RC = NO concentration in the reaction chamber, ppm
R = residence time of the reactant gases in the reaction chamber, minute
[NO]STD = concentration of the undiluted NO standard, ppm
FNO = NO flowrate, scm\3\/min
FO = O3 generator air flowrate, scm\3\/min
VRC = volume of the reaction chamber, scm\3\

    1.4.2 The flow conditions to be used in the GPT system are 
determined by the following procedure:
    (a) Determine FT, the total flow required at the output manifold 
(FT=analyzer demand plus 10 to 50% excess).
    (b) Establish [NO]OUT as the highest NO concentration 
(ppm) which will be required at the output manifold. [NO]OUT 
should be approximately equivalent to 90% of the upper range limit (URL) 
of the NO2 concentration range to be covered.
    (c) Determine FNO as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.079
    
    (d) Select a convenient or available reaction chamber volume. 
Initially, a trial VRC may be selected to be in the range of 
approximately 200 to 500 scm\3\.
    (e) Compute FO as
    
    
    (f) Compute tR as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.080
    
Verify that tR < 2 minutes. If not, select a reaction chamber with a 
smaller VRC.
    (g) Compute the diluent air flowrate as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.081
    
where:

FD = diluent air flowrate, scm\3\/min

    (h) If FO turns out to be impractical for the desired system, select 
a reaction chamber

[[Page 52]]

having a different VRC and recompute FO and FD.

    Note: A dynamic parameter lower than 2.75 ppm-minutes may be used if 
it can be determined empirically that quantitative reaction of 
O3 with NO occurs. A procedure for making this determination 
as well as a more detailed discussion of the above requirements and 
other related considerations is given in reference 13.

    1.5 Procedure.
    1.5.1 Assemble a dynamic calibration system such as the one shown in 
Figure 1.
    1.5.2 Insure that all flowmeters are calibrated under the conditions 
of use against a reliable standard such as a soap-bubble meter or wet-
test meter. All volumetric flowrates should be corrected to 25 [deg]C 
and 760 mm Hg. A discussion on the calibration of flowmeters is given in 
reference 13.
    1.5.3 Precautions must be taken to remove O2 and other 
contaminants from the NO pressure regulator and delivery system prior to 
the start of calibration to avoid any conversion of the standard NO to 
NO2. Failure to do so can cause significant errors in 
calibration. This problem may be minimized by (1) carefully evacuating 
the regulator, when possible, after the regulator has been connected to 
the cylinder and before opening the cylinder valve; (2) thoroughly 
flushing the regulator and delivery system with NO after opening the 
cylinder valve; (3) not removing the regulator from the cylinder between 
calibrations unless absolutely necessary. Further discussion of these 
procedures is given in reference 13.
    1.5.4 Select the operating range of the NO/NOX/
NO2 analyzer to be calibrated. In order to obtain maximum 
precision and accuracy for NO2 calibration, all three 
channels of the analyzer should be set to the same range. If operation 
of the NO and NOX channels on higher ranges is desired, 
subsequent recalibration of the NO and NOX channels on the 
higher ranges is recommended.

    Note: Some analyzer designs may require identical ranges for NO, 
NOX, and NO2 during operation of the analyzer.

    1.5.5 Connect the recorder output cable(s) of the NO/NOX/
NO2 analyzer to the input terminals of the strip chart 
recorder(s). All adjustments to the analyzer should be performed based 
on the appropriate strip chart readings. References to analyzer 
responses in the procedures given below refer to recorder responses.
    1.5.6 Determine the GPT flow conditions required to meet the dynamic 
parameter specification as indicated in 1.4.
    1.5.7 Adjust the diluent air and O3 generator air flows 
to obtain the flows determined in section 1.4.2. The total air flow must 
exceed the total demand of the analyzer(s) connected to the output 
manifold to insure that no ambient air is pulled into the manifold vent. 
Allow the analyzer to sample zero air until stable NO, NOX, 
and NO2 responses are obtained. After the responses have 
stabilized, adjust the analyzer zero control(s).

    Note: Some analyzers may have separate zero controls for NO, 
NOX, and NO2. Other analyzers may have separate 
zero controls only for NO and NOX, while still others may 
have only one zero control common to all three channels.

    Offsetting the analyzer zero adjustments to +5 percent of scale is 
recommended to facilitate observing negative zero drift. Record the 
stable zero air responses as ZNO, Znox, and Zno2.
    1.5.8 Preparation of NO and NOX calibration curves.
    1.5.8.1 Adjustment of NO span control. Adjust the NO flow from the 
standard NO cylinder to generate an NO concentration of approximately 80 
percent of the upper range limit (URL) of the NO range. This exact NO 
concentration is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.044

where:

[NO]OUT = diluted NO concentration at the output manifold, ppm

Sample this NO concentration until the NO and NOX responses 
have stabilized. Adjust the NO span control to obtain a recorder 
response as indicated below:

recorder response (percent scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.045

where:

URL = nominal upper range limit of the NO channel, ppm

    Note: Some analyzers may have separate span controls for NO, 
NOX, and NO2. Other analyzers may have separate 
span controls only for NO and NOX, while still others may 
have only one span control common to all three channels. When only one 
span control is available, the span adjustment is made on the NO channel 
of the analyzer.

If substantial adjustment of the NO span control is necessary, it may be 
necessary to recheck the zero and span adjustments by repeating steps 
1.5.7 and 1.5.8.1. Record the NO concentration and the analyzer's NO 
response.
    1.5.8.2 Adjustment of NOX span control. When adjusting 
the analyzer's NOX span control, the presence of any 
NO2 impurity in the standard NO cylinder must be taken into 
account. Procedures for determining the amount of NO2 
impurity in the standard NO

[[Page 53]]

cylinder are given in reference 13. The exact NOX 
concentration is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.046

where:

[NOX]OUT = diluted NOX concentration at 
the output manifold, ppm
[NO2]IMP = concentration of NO2 
impurity in the standard NO cylinder, ppm

Adjust the NOX span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.047

    Note: If the analyzer has only one span control, the span adjustment 
is made on the NO channel and no further adjustment is made here for 
NOX.

If substantial adjustment of the NOX span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 1.5.7 and 1.5.8.2. Record the NOX 
concentration and the analyzer's NOX response.
    1.5.8.3 Generate several additional concentrations (at least five 
evenly spaced points across the remaining scale are suggested to verify 
linearity) by decreasing FNO or increasing FD. For 
each concentration generated, calculate the exact NO and NOX 
concentrations using equations (9) and (11) respectively. Record the 
analyzer's NO and NOX responses for each concentration. Plot 
the analyzer responses versus the respective calculated NO and 
NOX concentrations and draw or calculate the NO and 
NOX calibration curves. For subsequent calibrations where 
linearity can be assumed, these curves may be checked with a two-point 
calibration consisting of a zero air point and NO and NOX 
concentrations of approximately 80% of the URL.
    1.5.9 Preparation of NO2 calibration curve.
    1.5.9.1 Assuming the NO2 zero has been properly adjusted 
while sampling zero air in step 1.5.7, adjust FO and 
FD as determined in section 1.4.2. Adjust FNO to 
generate an NO concentration near 90% of the URL of the NO range. Sample 
this NO concentration until the NO and NOX responses have 
stabilized. Using the NO calibration curve obtained in section 1.5.8, 
measure and record the NO concentration as [NO]orig. Using 
the NOX calibration curve obtained in section 1.5.8, measure 
and record the NOX concentration as 
[NOX]orig.
    1.5.9.2 Adjust the O3 generator to generate sufficient 
O3 to produce a decrease in the NO concentration equivalent 
to approximately 80% of the URL of the NO2 range. The 
decrease must not exceed 90% of the NO concentration determined in step 
1.5.9.1. After the analyzer responses have stabilized, record the 
resultant NO and NOX concentrations as [NO]rem and 
[NOX]rem.
    1.5.9.3 Calculate the resulting NO2 concentration from:
    [GRAPHIC] [TIFF OMITTED] TC08NO91.082
    
where:

[NO2]OUT = diluted NO2 concentration at 
the output manifold, ppm
[NO]orig = original NO concentration, prior to addition of 
O3, ppm
[NO]rem = NO concentration remaining after addition of 
O3, ppm

Adjust the NO2 span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.048

    Note: If the analyzer has only one or two span controls, the span 
adjustments are made on the NO channel or NO and NOX channels 
and no further adjustment is made here for NO2.

If substantial adjustment of the NO2 span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 1.5.7 and 1.5.9.3. Record the NO2 
concentration and the corresponding analyzer NO2 and 
NOX responses.
    1.5.9.4 Maintaining the same FNO, FO, and 
FD as in section 1.5.9.1, adjust the ozone generator to 
obtain several other concentrations of NO2 over the 
NO2 range (at least five evenly spaced points across the 
remaining scale are suggested). Calculate each NO2 
concentration using equation (13) and record the corresponding analyzer 
NO2 and NOX responses. Plot the analyzer's 
NO2 responses versus the corresponding calculated 
NO2 concentrations and draw or calculate the NO2 
calibration curve.
    1.5.10 Determination of converter efficiency.

[[Page 54]]

    1.5.10.1 For each NO2 concentration generated during the 
preparation of the NO2 calibration curve (see section 1.5.9) 
calculate the concentration of NO2 converted from:
[GRAPHIC] [TIFF OMITTED] TC08NO91.083

where:

[NO2]CONV = concentration of NO2 
converted, ppm
[NOX]orig = original NOX concentration 
prior to addition of O3, ppm
[NOX]rem = NOX concentration remaining 
after addition of O3, ppm

    Note: Supplemental information on calibration and other procedures 
in this method are given in reference 13.

Plot [NO2]CONV (y-axis) versus 
[NO2]OUT (x-axis) and draw or calculate the 
converter efficiency curve. The slope of the curve times 100 is the 
average converter efficiency, EC The average converter 
efficiency must be greater than 96%; if it is less than 96%, replace or 
service the converter.
    2. Alternative B--NO2 permeation device.
    Major equipment required:
    Stable O3 generator.
    Chemiluminescence NO/NOX/NO2 analyzer with strip chart 
recorder(s).
    NO concentration standard.
    NO2 concentration standard.
    2.1 Principle. Atmospheres containing accurately known 
concentrations of nitrogen dioxide are generated by means of a 
permeation device. (10) The permeation device emits NO2 at a 
known constant rate provided the temperature of the device is held 
constant (0.1 [deg]C) and the device has been 
accurately calibrated at the temperature of use. The NO2 
emitted from the device is diluted with zero air to produce 
NO2 concentrations suitable for calibration of the 
NO2 channel of the NO/NOX/NO2 analyzer. An NO 
concentration standard is used for calibration of the NO and NOX 
channels of the analyzer.
    2.2 Apparatus. A typical system suitable for generating the required 
NO and NO2 concentrations is shown in Figure 2. All 
connections between components downstream from the permeation device 
should be of glass, Teflon [reg], or other non-reactive 
material.
    2.2.1 Air flow controllers. Devices capable of maintaining constant 
air flows within 2% of the required flowrate.
    2.2.2 NO flow controller. A device capable of maintaining constant 
NO flows within 2% of the required flowrate. 
Component parts in contact with the NO must be of a non-reactive 
material.
    2.2.3 Air flowmeters. Calibrated flowmeters capable of measuring and 
monitoring air flowrates with an accuracy of 2% of 
the measured flowrate.
    2.2.4 NO flowmeter. A calibrated flowmeter capable of measuring and 
monitoring NO flowrates with an accuracy of 2% of 
the measured flowrate. (Rotameters have been reported to operate 
unreliably when measuring low NO flows and are not recommended.)
    2.2.5 Pressure regulator for standard NO cylinder. This regulator 
must have a non-reactive diaphragm and internal parts and a suitable 
delivery pressure.
    2.2.6 Drier. Scrubber to remove moisture from the permeation device 
air system. The use of the drier is optional with NO2 
permeation devices not sensitive to moisture. (Refer to the supplier's 
instructions for use of the permeation device.)
    2.2.7 Constant temperature chamber. Chamber capable of housing the 
NO2 permeation device and maintaining its temperature to 
within 0.1 [deg]C.
    2.2.8 Temperature measuring device. Device capable of measuring and 
monitoring the temperature of the NO2 permeation device with 
an accuracy of 0.05 [deg]C.
    2.2.9 Valves. A valve may be used as shown in Figure 2 to divert the 
NO2 from the permeation device when zero air or NO is 
required at the manifold. A second valve may be used to divert the NO 
flow when zero air or NO2 is required at the manifold.
    The valves should be constructed of glass, Teflon [reg], 
or other nonreactive material.
    2.2.10 Mixing chamber. A chamber constructed of glass, Teflon 
[reg], or other nonreactive material and designed to provide 
thorough mixing of pollutant gas streams and diluent air.
    2.2.11 Output manifold. The output manifold should be constructed of 
glass, Teflon [reg], or other non-reactive material and 
should be of sufficient diameter to insure an insignificant pressure 
drop at the analyzer connection. The system must have a vent designed to 
insure atmospheric pressure at the manifold and to prevent ambient air 
from entering the manifold.
    2.3 Reagents.
    2.3.1 Calibration standards. Calibration standards are required for 
both NO and NO2. The reference standard for the calibration 
may be either an NO or NO2 standard, and must be traceable to 
a National Bureau of Standards (NBS) NO in N2 Standard 
Reference Material (SRM 1683 or SRM 1684), and NBS NO2 
Standard Reference Material (SRM 1629), or an NBS/EPA-approved 
commercially

[[Page 55]]

available Certified Reference Material (CRM). CRM's are described in 
Reference 14, and a list of CRM sources is available from the address 
shown for Reference 14. Reference 15 gives recommended procedures for 
certifying an NO gas cylinder against an NO SRM or CRM and for 
certifying an NO2 permeation device against an NO2 
SRM. Reference 13 contains procedures for certifying an NO gas cylinder 
against an NO2 SRM and for certifying an NO2 
permeation device against an NO SRM or CRM. A procedure for determining 
the amount of NO2 impurity in an NO cylinder is also 
contained in Reference 13. The NO or NO2 standard selected as 
the reference standard must be used to certify the other standard to 
ensure consistency between the two standards.
    2.3.1.1 NO2 Concentration standard. A permeation device 
suitable for generating NO2 concentrations at the required 
flow-rates over the required concentration range. If the permeation 
device is used as the reference standard, it must be traceable to an SRM 
or CRM as specified in 2.3.1. If an NO cylinder is used as the reference 
standard, the NO2 permeation device must be certified against 
the NO standard according to the procedure given in Reference 13. The 
use of the permeation device should be in strict accordance with the 
instructions supplied with the device. Additional information regarding 
the use of permeation devices is given by Scaringelli et al. (11) and 
Rook et al. (12).
    2.3.1.2 NO Concentration standard. Gas cylinder containing 50 to 100 
ppm NO in N2 with less than 1 ppm NO2. If this 
cylinder is used as the reference standard, the cylinder must be 
traceable to an SRM or CRM as specified in 2.3.1. If an NO2 
permeation device is used as the reference standard, the NO cylinder 
must be certified against the NO2 standard according to the 
procedure given in Reference 13. The cylinder should be recertified on a 
regular basis as determined by the local quality control program.
    2.3.3 Zero air. Air, free of contaminants which might react with NO 
or NO2 or cause a detectable response on the NO/NOX/
NO2 analyzer. When using permeation devices that are 
sensitive to moisture, the zero air passing across the permeation device 
must be dry to avoid surface reactions on the device. (Refer to the 
supplier's instructions for use of the permeation device.) A procedure 
for generating zero air is given in reference 13.
    2.4 Procedure.
    2.4.1 Assemble the calibration apparatus such as the typical one 
shown in Figure 2.
    2.4.2 Insure that all flowmeters are calibrated under the conditions 
of use against a reliable standard such as a soap bubble meter or wet-
test meter. All volumetric flowrates should be corrected to 25 [deg]C 
and 760 mm Hg. A discussion on the calibration of flowmeters is given in 
reference 13.
    2.4.3 Install the permeation device in the constant temperature 
chamber. Provide a small fixed air flow (200-400 scm\3\/min) across the 
device. The permeation device should always have a continuous air flow 
across it to prevent large buildup of NO2 in the system and a 
consequent restabilization period. Record the flowrate as FP. Allow the 
device to stabilize at the calibration temperature for at least 24 
hours. The temperature must be adjusted and controlled to within 0.1 [deg]C or less of the calibration temperature as 
monitored with the temperature measuring device.
    2.4.4 Precautions must be taken to remove O2 and other 
contaminants from the NO pressure regulator and delivery system prior to 
the start of calibration to avoid any conversion of the standard NO to 
NO2. Failure to do so can cause significant errors in 
calibration. This problem may be minimized by
    (1) Carefully evacuating the regulator, when possible, after the 
regulator has been connected to the cylinder and before opening the 
cylinder valve;
    (2) Thoroughly flushing the regulator and delivery system with NO 
after opening the cylinder valve;
    (3) Not removing the regulator from the cylinder between 
calibrations unless absolutely necessary. Further discussion of these 
procedures is given in reference 13.
    2.4.5 Select the operating range of the NO/NOX NO2 
analyzer to be calibrated. In order to obtain maximum precision and 
accuracy for NO2 calibration, all three channels of the 
analyzer should be set to the same range. If operation of the NO and NOX 
channels on higher ranges is desired, subsequent recalibration of the NO 
and NOX channels on the higher ranges is recommended.

    Note: Some analyzer designs may require identical ranges for NO, 
NOX, and NO2 during operation of the analyzer.

    2.4.6 Connect the recorder output cable(s) of the NO/NOX/
NO2 analyzer to the input terminals of the strip chart 
recorder(s). All adjustments to the analyzer should be performed based 
on the appropriate strip chart readings. References to analyzer 
responses in the procedures given below refer to recorder responses.
    2.4.7 Switch the valve to vent the flow from the permeation device 
and adjust the diluent air flowrate, FD, to provide zero air at the 
output manifold. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is pulled into the manifold vent. Allow the analyzer to sample zero 
air until stable NO, NOX, and NO2 responses are obtained. 
After the responses have stabilized, adjust the analyzer zero 
control(s).

    Note: Some analyzers may have separate zero controls for NO, NOX, 
and NO2. Other analyzers may have separate zero controls

[[Page 56]]

only for NO and NOX, while still others may have only one zero common 
control to all three channels.

Offsetting the analyzer zero adjustments to +5% of scale is recommended 
to facilitate observing negative zero drift. Record the stable zero air 
responses as ZNO, ZNOX, and 
ZNO2.
    2.4.8 Preparation of NO and NOX calibration curves.
    2.4.8.1 Adjustment of NO span control. Adjust the NO flow from the 
standard NO cylinder to generate an NO concentration of approximately 
80% of the upper range limit (URL) of the NO range. The exact NO 
concentration is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.049

where:

[NO]OUT = diluted NO concentration at the output manifold, 
ppm
FNO = NO flowrate, scm\3\/min
[NO]STD=concentration of the undiluted NO standard, ppm
FD = diluent air flowrate, scm\3\/min

Sample this NO concentration until the NO and NOX responses have 
stabilized. Adjust the NO span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.050

[GRAPHIC] [TIFF OMITTED] TR31AU93.051

where:

URL = nominal upper range limit of the NO channel, ppm

    Note: Some analyzers may have separate span controls for NO, NOX, 
and NO2. Other analyzers may have separate span controls only 
for NO and NOX, while still others may have only one span control common 
to all three channels. When only one span control is available, the span 
adjustment is made on the NO channel of the analyzer.

If substantial adjustment of the NO span control is necessary, it may be 
necessary to recheck the zero and span adjustments by repeating steps 
2.4.7 and 2.4.8.1. Record the NO concentration and the analyzer's NO 
response.
    2.4.8.2 Adjustment of NOX span control. When adjusting the 
analyzer's NOX span control, the presence of any NO2 impurity 
in the standard NO cylinder must be taken into account. Procedures for 
determining the amount of NO2 impurity in the standard NO 
cylinder are given in reference 13. The exact NOX concentration is 
calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.052

where:

[NOX]OUT = diluted NOX cencentration at 
the output manifold, ppm
[NO2]IMP = concentration of NO2 
impurity in the standard NO cylinder, ppm

Adjust the NOX span control to obtain a convenient recorder response as 
indicated below:

recorder response (% scale)
[GRAPHIC] [TIFF OMITTED] TR31AU93.053

    Note: If the analyzer has only one span control, the span adjustment 
is made on the NO channel and no further adjustment is made here for 
NOX.

If substantial adjustment of the NOX span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 2.4.7 and 2.4.8.2. Record the NOX 
concentration and the analyzer's NOX response.
    2.4.8.3 Generate several additional concentrations (at least five 
evenly spaced points across the remaining scale are suggested to verify 
linearity) by decreasing FNO or increasing FD. For each 
concentration generated, calculate the exact NO and NOX 
concentrations using equations (16) and (18) respectively. Record the 
analyzer's NO and NOX responses for each concentration. Plot 
the analyzer responses versus the respective calculated NO and 
NOX concentrations and draw or calculate the NO and 
NOX calibration curves. For subsequent calibrations where 
linearity can be assumed, these curves may be checked with a two-point 
calibration consisting of a zero point and NO and NOX 
concentrations of approximately 80 percent of the URL.
    2.4.9 Preparation of NO2 calibration curve.
    2.4.9.1 Remove the NO flow. Assuming the NO2 zero has 
been properly adjusted while sampling zero air in step 2.4.7, switch the 
valve to provide NO2 at the output manifold.
    2.4.9.2 Adjust FD to generate an NO2 concentration of 
approximately 80 percent of the URL of the NO2 range. The 
total air flow must exceed the demand of the analyzer(s) under 
calibration. The actual concentration of NO2 is calculated 
from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.054

where:


[[Page 57]]


[NO2]OUT = diluted NO2 concentration at 
the output manifold, ppm
R = permeation rate, [micro]g/min
K = 0.532 [micro]l NO2/[micro]g NO2 (at 25 [deg]C 
and 760 mm Hg)
Fp = air flowrate across permeation device, scm\3\/min
FD = diluent air flowrate, scm\3\/min

Sample this NO2 concentration until the NOX and 
NO2 responses have stabilized. Adjust the NO2 span 
control to obtain a recorder response as indicated below:

recorder response (% scale)
[GRAPHIC] [TIFF OMITTED] TR31AU93.055

    Note: If the analyzer has only one or two span controls, the span 
adjustments are made on the NO channel or NO and NOX channels 
and no further adjustment is made here for NO2.

If substantial adjustment of the NO2 span control is 
necessary it may be necessary to recheck the zero and span adjustments 
by repeating steps 2.4.7 and 2.4.9.2. Record the NO2 
concentration and the analyzer's NO2 response. Using the 
NOX calibration curve obtained in step 2.4.8, measure and 
record the NOX concentration as [NOX]M.
    2.4.9.3 Adjust FD to obtain several other concentrations of 
NO2 over the NO2 range (at least five evenly 
spaced points across the remaining scale are suggested). Calculate each 
NO2 concentration using equation (20) and record the 
corresponding analyzer NO2 and NOX responses. Plot 
the analyzer's NO2 responses versus the corresponding 
calculated NO2 concentrations and draw or calculate the 
NO2 calibration curve.
    2.4.10 Determination of converter efficiency.
    2.4.10.1 Plot [NOX]M (y-axis) versus 
[NO2]OUT (x-axis) and draw or calculate the 
converter efficiency curve. The slope of the curve times 100 is the 
average converter efficiency, EC. The average converter efficiency must 
be greater than 96 percent; if it is less than 96 percent, replace or 
service the converter.

    Note: Supplemental information on calibration and other procedures 
in this method are given in reference 13.

    3. Frequency of calibration. The frequency of calibration, as well 
as the number of points necessary to establish the calibration curve and 
the frequency of other performance checks, will vary from one analyzer 
to another. The user's quality control program should provide guidelines 
for initial establishment of these variables and for subsequent 
alteration as operational experience is accumulated. Manufacturers of 
analyzers should include in their instruction/operation manuals 
information and guidance as to these variables and on other matters of 
operation, calibration, and quality control.

                               References

    1. A. Fontijn, A. J. Sabadell, and R. J. Ronco, ``Homogeneous 
Chemiluminescent Measurement of Nitric Oxide with Ozone,'' Anal. Chem., 
42, 575 (1970).
    2. D. H. Stedman, E. E. Daby, F. Stuhl, and H. Niki, ``Analysis of 
Ozone and Nitric Oxide by a Chemiluminiscent Method in Laboratory and 
Atmospheric Studies of Photochemical Smog,'' J. Air Poll. Control 
Assoc., 22, 260 (1972).
    3. B. E. Martin, J. A. Hodgeson, and R. K. Stevens, ``Detection of 
Nitric Oxide Chemiluminescence at Atmospheric Pressure,'' Presented at 
164th National ACS Meeting, New York City, August 1972.
    4. J. A. Hodgeson, K. A. Rehme, B. E. Martin, and R. K. Stevens, 
``Measurements for Atmospheric Oxides of Nitrogen and Ammonia by 
Chemiluminescence,'' Presented at 1972 APCA Meeting, Miami, FL, June 
1972.
    5. R. K. Stevens and J. A. Hodgeson, ``Applications of 
Chemiluminescence Reactions to the Measurement of Air Pollutants,'' 
Anal. Chem., 45, 443A (1973).
    6. L. P. Breitenbach and M. Shelef, ``Development of a Method for 
the Analysis of NO2 and NH3 by NO-Measuring 
Instruments,'' J. Air Poll. Control Assoc., 23, 128 (1973).
    7. A. M. Winer, J. W. Peters, J. P. Smith, and J. N. Pitts, Jr., 
``Response of Commercial Chemiluminescent NO-NO2 Analyzers to 
Other Nitrogen-Containing Compounds,'' Environ. Sci. Technol., 8, 1118 
(1974).
    8. K. A. Rehme, B. E. Martin, and J. A. Hodgeson, Tentative Method 
for the Calibration of Nitric Oxide, Nitrogen Dioxide, and Ozone 
Analyzers by Gas Phase Titration,'' EPA-R2-73-246, March 1974.
    9. J. A. Hodgeson, R. K. Stevens, and B. E. Martin, ``A Stable Ozone 
Source Applicable as a Secondary Standard for Calibration of Atmospheric 
Monitors,'' ISA Transactions, 11, 161 (1972).
    10. A. E. O'Keeffe and G. C. Ortman, ``Primary Standards for Trace 
Gas Analysis,'' Anal. Chem., 38, 760 (1966).
    11. F. P. Scaringelli, A. E. O'Keeffe, E. Rosenberg, and J. P. Bell, 
``Preparation of Known Concentrations of Gases and Vapors with 
Permeation Devices Calibrated Gravimetrically,'' Anal. Chem., 42, 871 
(1970).
    12. H. L. Rook, E. E. Hughes, R. S. Fuerst, and J. H. Margeson, 
``Operation Characteristics of NO2 Permeation Devices,'' 
Presented at 167th National ACS Meeting, Los Angeles, CA, April 1974.
    13. E. C. Ellis, ``Technical Assistance Document for the 
Chemiluminescence Measurement of Nitrogen Dioxide,'' EPA-E600/4-75-003 
(Available in draft form from the United States Environmental Protection 
Agency, Department E (MD-76), Environmental Monitoring and Support 
Laboratory, Research Triangle Park, NC 27711).

[[Page 58]]

    14. A Procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, Joint publication by NBS and EPA. Available from the U.S. 
Environmental Protection Agency, Environmental Monitoring Systems 
Laboratory (MD-77), Research Triangle Park, NC 27711, May 1981.
    15. Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume II, Ambient Air Specific Methods. The U.S. Environmental 
Protection Agency, Environmental Monitoring Systems Laboratory, Research 
Triangle Park, NC 27711. Publication No. EAP-600/4-77-027a.



[[Page 59]]





[41 FR 52688, Dec. 1, 1976, as amended at 48 FR 2529, Jan 20, 1983]



 Sec. Appendix G to Part 50--Reference Method for the Determination of 
     Lead in Suspended Particulate Matter Collected From Ambient Air

    1. Principle and applicability.
    1.1 Ambient air suspended particulate matter is collected on a 
glass-fiber filter for 24 hours using a high volume air sampler. The 
analysis of the 24-hour samples may be performed for either individual 
samples or composites of the samples collected over a calendar month or 
quarter, provided that the compositing procedure has been approved in 
accordance with section 2.8 of appendix C to part 58 of this chapter--
Modifications of methods by users. (Guidance or assistance in requesting 
approval under Section 2.8 can be obtained from the address given in 
section 2.7 of appendix C to part 58 of this chapter.)
    1.2 Lead in the particulate matter is solubilized by extraction with 
nitric acid (HNO3), facilitated by heat or by a mixture of 
HNO3 and hydrochloric acid (HCl) facilitated by 
ultrasonication.
    1.3 The lead content of the sample is analyzed by atomic absorption 
spectrometry using an air-acetylene flame, the 283.3 or 217.0 nm lead 
absorption line, and the optimum instrumental conditions recommended by 
the manufacturer.
    1.4 The ultrasonication extraction with HNO3/HCl will 
extract metals other than lead from ambient particulate matter.
    2. Range, sensitivity, and lower detectable limit. The values given 
below are typical of the methods capabilities. Absolute values will vary 
for individual situations depending on the type of instrument used, the 
lead line, and operating conditions.
    2.1 Range. The typical range of the method is 0.07 to 7.5 [micro]g 
Pb/m\3\ assuming an upper linear range of analysis of 15 [micro]g/ml and 
an air volume of 2,400 m\3\.
    2.2 Sensitivity. Typical sensitivities for a 1 percent change in 
absorption (0.0044 absorbance units) are 0.2 and 0.5 [micro]g Pb/ml for 
the 217.0 and 283.3 nm lines, respectively.
    2.3 Lower detectable limit (LDL). A typical LDL is 0.07 [micro]g Pb/
m\3\. The above value was calculated by doubling the between-laboratory 
standard deviation obtained for the lowest measurable lead concentration 
in a collaborative test of the method.(15) An air volume of 2,400 m\3\ 
was assumed.
    3. Interferences. Two types of interferences are possible: chemical 
and light scattering.
    3.1 Chemical. Reports on the absence (1, 2, 3, 4, 5) of chemical 
interferences far outweigh those reporting their presence, (6) 
therefore, no correction for chemical interferences is given here. If 
the analyst suspects that the sample matrix is causing a chemical 
interference, the interference can be verified and corrected for by 
carrying out the analysis

[[Page 60]]

with and without the method of standard additions.(7)
    3.2 Light scattering. Nonatomic absorption or light scattering, 
produced by high concentrations of dissolved solids in the sample, can 
produce a significant interference, especially at low lead 
concentrations. (2) The interference is greater at the 217.0 nm line 
than at the 283.3 nm line. No interference was observed using the 283.3 
nm line with a similar method.(1)
    Light scattering interferences can, however, be corrected for 
instrumentally. Since the dissolved solids can vary depending on the 
origin of the sample, the correction may be necessary, especially when 
using the 217.0 nm line. Dual beam instruments with a continuum source 
give the most accurate correction. A less accurate correction can be 
obtained by using a nonabsorbing lead line that is near the lead 
analytical line. Information on use of these correction techniques can 
be obtained from instrument manufacturers' manuals.
    If instrumental correction is not feasible, the interference can be 
eliminated by use of the ammonium pyrrolidinecarbodithioate-
methylisobutyl ketone, chelation-solvent extraction technique of sample 
preparation.(8)
    4. Precision and bias.
    4.1 The high-volume sampling procedure used to collect ambient air 
particulate matter has a between-laboratory relative standard deviation 
of 3.7 percent over the range 80 to 125 [micro]g/m\3\.(9) The combined 
extraction-analysis procedure has an average within-laboratory relative 
standard deviation of 5 to 6 percent over the range 1.5 to 15 [micro]g 
Pb/ml, and an average between laboratory relative standard deviation of 
7 to 9 percent over the same range. These values include use of either 
extraction procedure.
    4.2 Single laboratory experiments and collaborative testing indicate 
that there is no significant difference in lead recovery between the hot 
and ultrasonic extraction procedures.(15)
    5. Apparatus.
    5.1 Sampling.
    5.1.1 High-Volume Sampler. Use and calibrate the sampler as 
described in appendix B to this part.
    5.2 Analysis.
    5.2.1 Atomic absorption spectrophotometer. Equipped with lead hollow 
cathode or electrodeless discharge lamp.
    5.2.1.1 Acetylene. The grade recommended by the instrument 
manufacturer should be used. Change cylinder when pressure drops below 
50-100 psig.
    5.2.1.2 Air. Filtered to remove particulate, oil, and water.
    5.2.2 Glassware. Class A borosilicate glassware should be used 
throughout the analysis.
    5.2.2.1 Beakers. 30 and 150 ml. graduated, Pyrex.
    5.2.2.2 Volumetric flasks. 100-ml.
    5.2.2.3 Pipettes. To deliver 50, 30, 15, 8, 4, 2, 1 ml.
    5.2.2.4 Cleaning. All glassware should be scrupulously cleaned. The 
following procedure is suggested. Wash with laboratory detergent, rinse, 
soak for 4 hours in 20 percent (w/w) HNO3, rinse 3 times with 
distilled-deionized water, and dry in a dust free manner.
    5.2.3 Hot plate.
    5.2.4. Ultrasonication water bath, unheated. Commercially available 
laboratory ultrasonic cleaning baths of 450 watts or higher ``cleaning 
power,'' i.e., actual ultrasonic power output to the bath have been 
found satisfactory.
    5.2.5 Template. To aid in sectioning the glass-fiber filter. See 
figure 1 for dimensions.
    5.2.6 Pizza cutter. Thin wheel. Thickness 1mm.
    5.2.7 Watch glass.
    5.2.8 Polyethylene bottles. For storage of samples. Linear 
polyethylene gives better storage stability than other polyethylenes and 
is preferred.
    5.2.9 Parafilm ``M''.\1\ American Can Co., Marathon Products, 
Neenah, Wis., or equivalent.
---------------------------------------------------------------------------

    \1\ Mention of commercial products does not imply endorsement by the 
U.S. Environmental Protection Agency.
---------------------------------------------------------------------------

    6. Reagents.
    6.1 Sampling.
    6.1.1 Glass fiber filters. The specifications given below are 
intended to aid the user in obtaining high quality filters with 
reproducible properties. These specifications have been met by EPA 
contractors.
    6.1.1.1 Lead content. The absolute lead content of filters is not 
critical, but low values are, of course, desirable. EPA typically 
obtains filters with a lead content of 75 [micro]g/filter.
    It is important that the variation in lead content from filter to 
filter, within a given batch, be small.
    6.1.1.2 Testing.
    6.1.1.2.1 For large batches of filters (500 filters) 
select at random 20 to 30 filters from a given batch. For small batches 
(500 filters) a lesser number of filters may be taken. Cut 
one \3/4\x8 strip from each filter anywhere in the 
filter. Analyze all strips, separately, according to the directions in 
sections 7 and 8.
    6.1.1.2.2 Calculate the total lead in each filter as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.084
    
where:

Fb = Amount of lead per 72 square inches of filter, [micro]g.

    6.1.1.2.3 Calculate the mean, Fb, of the values and the 
relative standard deviation

[[Page 61]]

(standard deviation/mean x 100). If the relative standard deviation is 
high enough so that, in the analysts opinion, subtraction of 
Fb, (section 10.3) may result in a significant error in the 
[micro]g Pb/m\3\, the batch should be rejected.
    6.1.1.2.4 For acceptable batches, use the value of Fb to 
correct all lead analyses (section 10.3) of particulate matter collected 
using that batch of filters. If the analyses are below the LDL (section 
2.3) no correction is necessary.
    6.2 Analysis.
    6.2.1 Concentrated (15.6 M) HNO3. ACS reagent grade 
HNO3 and commercially available redistilled HNO3 
has found to have sufficiently low lead concentrations.
    6.2.2 Concentrated (11.7 M) HCl. ACS reagent grade.
    6.2.3 Distilled-deionized water. (D.I. water).
    6.2.4 3 M HNO3. This solution is used in the hot 
extraction procedure. To prepare, add 192 ml of concentrated 
HNO3 to D.I. water in a 1 l volumetric flask. Shake well, 
cool, and dilute to volume with D.I. water. Caution: Nitric acid fumes 
are toxic. Prepare in a well ventilated fume hood.
    6.2.5 0.45 M HNO3. This solution is used as the matrix 
for calibration standards when using the hot extraction procedure. To 
prepare, add 29 ml of concentrated HNO3 to D.I. water in a 1 
l volumetric flask. Shake well, cool, and dilute to volume with D.I. 
water.
    6.2.6 2.6 M HNO3+0 to 0.9 M HCl. This solution is used in 
the ultrasonic extraction procedure. The concentration of HCl can be 
varied from 0 to 0.9 M. Directions are given for preparation of a 2.6 M 
HNO3+0.9 M HCl solution. Place 167 ml of concentrated 
HNO3 into a 1 l volumetric flask and add 77 ml of 
concentrated HCl. Stir 4 to 6 hours, dilute to nearly 1 l with D.I. 
water, cool to room temperature, and dilute to 1 l.
    6.2.7 0.40 M HNO3 + X M HCl. This solution is used as the 
matrix for calibration standards when using the ultrasonic extraction 
procedure. To prepare, add 26 ml of concentrated HNO3, plus 
the ml of HCl required, to a 1 l volumetric flask. Dilute to nearly 1 l 
with D.I. water, cool to room temperature, and dilute to 1 l. The amount 
of HCl required can be determined from the following equation:
[GRAPHIC] [TIFF OMITTED] TC08NO91.085

where:

y = ml of concentrated HCl required.
x = molarity of HCl in 6.2.6.
0.15 = dilution factor in 7.2.2.

    6.2.8 Lead nitrate, Pb(NO3)2. ACS reagent 
grade, purity 99.0 percent. Heat for 4 hours at 120 [deg]C and cool in a 
desiccator.
    6.3 Calibration standards.
    6.3.1 Master standard, 1000 [micro]g Pb/ml in HNO3. 
Dissolve 1.598 g of Pb(NO3)2 in 0.45 M 
HNO3 contained in a 1 l volumetric flask and dilute to volume 
with 0.45 M HNO3.
    6.3.2 Master standard, 1000 [micro]g Pb/ml in HNO3/HCl. 
Prepare as in section 6.3.1 except use the HNO3/HCl solution 
in section 6.2.7.
    Store standards in a polyethylene bottle. Commercially available 
certified lead standard solutions may also be used.
    7. Procedure.
    7.1 Sampling. Collect samples for 24 hours using the procedure 
described in reference 10 with glass-fiber filters meeting the 
specifications in section 6.1.1. Transport collected samples to the 
laboratory taking care to minimize contamination and loss of sample. 
(16).
    7.2 Sample preparation.
    7.2.1 Hot extraction procedure.
    7.2.1.1 Cut a \3/4\x8 strip from the exposed 
filter using a template and a pizza cutter as described in Figures 1 and 
2. Other cutting procedures may be used.
    Lead in ambient particulate matter collected on glass fiber filters 
has been shown to be uniformly distributed across the filter. \1,3,11\ 
Another study \12\ has shown that when sampling near a roadway, strip 
position contributes significantly to the overall variability associated 
with lead analyses. Therefore, when sampling near a roadway, additional 
strips should be analyzed to minimize this variability.
    7.2.1.2 Fold the strip in half twice and place in a 150-ml beaker. 
Add 15 ml of 3 M HNO3 to cover the sample. The acid should 
completely cover the sample. Cover the beaker with a watch glass.
    7.2.1.3 Place beaker on the hot-plate, contained in a fume hood, and 
boil gently for 30 min. Do not let the sample evaporate to dryness. 
Caution: Nitric acid fumes are toxic.
    7.2.1.4 Remove beaker from hot plate and cool to near room 
temperature.
    7.2.1.5 Quantitatively transfer the sample as follows:
    7.2.1.5.1 Rinse watch glass and sides of beaker with D.I. water.
    7.2.1.5.2 Decant extract and rinsings into a 100-ml volumetric 
flask.
    7.2.1.5.3 Add D.I. water to 40 ml mark on beaker, cover with watch 
glass, and set aside for a minimum of 30 minutes. This is a critical 
step and cannot be omitted since it allows the HNO3 trapped 
in the filter to diffuse into the rinse water.
    7.2.1.5.4 Decant the water from the filter into the volumetric 
flask.
    7.2.1.5.5 Rinse filter and beaker twice with D.I. water and add 
rinsings to volumetric flask until total volume is 80 to 85 ml.
    7.2.1.5.6 Stopper flask and shake vigorously. Set aside for 
approximately 5 minutes or until foam has dissipated.
    7.2.1.5.7 Bring solution to volume with D.I. water. Mix thoroughly.

[[Page 62]]

    7.2.1.5.8 Allow solution to settle for one hour before proceeding 
with analysis.
    7.2.1.5.9 If sample is to be stored for subsequent analysis, 
transfer to a linear polyethylene bottle.
    7.2.2 Ultrasonic extraction procedure.
    7.2.2.1 Cut a \3/4\x8 strip from the exposed 
filter as described in section 7.2.1.1.
    7.2.2.2 Fold the strip in half twice and place in a 30 ml beaker. 
Add 15 ml of the HNO3/HCl solution in section 6.2.6. The acid 
should completely cover the sample. Cover the beaker with parafilm.
    The parafilm should be placed over the beaker such that none of the 
parafilm is in contact with water in the ultrasonic bath. Otherwise, 
rinsing of the parafilm (section 7.2.2.4.1) may contaminate the sample.
    7.2.2.3 Place the beaker in the ultrasonication bath and operate for 
30 minutes.
    7.2.2.4 Quantitatively transfer the sample as follows:
    7.2.2.4.1 Rinse parafilm and sides of beaker with D.I. water.
    7.2.2.4.2 Decant extract and rinsings into a 100 ml volumetric 
flask.
    7.2.2.4.3 Add 20 ml D.I. water to cover the filter strip, cover with 
parafilm, and set aside for a minimum of 30 minutes. This is a critical 
step and cannot be omitted. The sample is then processed as in sections 
7.2.1.5.4 through 7.2.1.5.9.

    Note: Samples prepared by the hot extraction procedure are now in 
0.45 M HNO3. Samples prepared by the ultrasonication 
procedure are in 0.40 M HNO3 + X M HCl.

    8. Analysis.
    8.1 Set the wavelength of the monochromator at 283.3 or 217.0 nm. 
Set or align other instrumental operating conditions as recommended by 
the manufacturer.
    8.2 The sample can be analyzed directly from the volumetric flask, 
or an appropriate amount of sample decanted into a sample analysis tube. 
In either case, care should be taken not to disturb the settled solids.
    8.3 Aspirate samples, calibration standards and blanks (section 9.2) 
into the flame and record the equilibrium absorbance.
    8.4 Determine the lead concentration in [micro]g Pb/ml, from the 
calibration curve, section 9.3.
    8.5 Samples that exceed the linear calibration range should be 
diluted with acid of the same concentration as the calibration standards 
and reanalyzed.
    9. Calibration.
    9.1 Working standard, 20 [micro]g Pb/ml. Prepared by diluting 2.0 ml 
of the master standard (section 6.3.1 if the hot acid extraction was 
used or section 6.3.2 if the ultrasonic extraction procedure was used) 
to 100 ml with acid of the same concentration as used in preparing the 
master standard.
    9.2 Calibration standards. Prepare daily by diluting the working 
standard, with the same acid matrix, as indicated below. Other lead 
concentrations may be used.

------------------------------------------------------------------------
                                                           Concentration
Volume of 20 [micro]g/ml working standard, ml     Final     [micro]g Pb/
                                               volume, ml        ml
------------------------------------------------------------------------
0............................................         100             0
1.0..........................................         200           0.1
2.0..........................................         200           0.2
2.0..........................................         100           0.4
4.0..........................................         100           0.8
8.0..........................................         100           1.6
15.0.........................................         100           3.0
30.0.........................................         100           6.0
50.0.........................................         100          10.0
100.0........................................         100          20.0
------------------------------------------------------------------------

    9.3 Preparation of calibration curve. Since the working range of 
analysis will vary depending on which lead line is used and the type of 
instrument, no one set of instructions for preparation of a calibration 
curve can be given. Select standards (plus the reagent blank), in the 
same acid concentration as the samples, to cover the linear absorption 
range indicated by the instrument manufacturer. Measure the absorbance 
of the blank and standards as in section 8.0. Repeat until good 
agreement is obtained between replicates. Plot absorbance (y-axis) 
versus concentration in [micro]g Pb/ml (x-axis). Draw (or compute) a 
straight line through the linear portion of the curve. Do not force the 
calibration curve through zero. Other calibration procedures may be 
used.
    To determine stability of the calibration curve, remeasure--
alternately--one of the following calibration standards for every 10th 
sample analyzed: Concentration <=1 [micro]g Pb/ml; concentration <=10 
[micro]g Pb/ml. If either standard deviates by more than 5 percent from 
the value predicted by the calibration curve, recalibrate and repeat the 
previous 10 analyses.
    10. Calculation.
    10.1 Measured air volume. Calculate the measured air volume at 
Standard Temperature and Pressure as described in Reference 10.
    10.2 Lead concentration. Calculate lead concentration in the air 
sample.

[[Page 63]]



where:

C = Concentration, [micro]g Pb/sm\3\.
[micro]g Pb/ml = Lead concentration determined from section 8.
100 ml/strip = Total sample volume.
12 strips = Total useable filter area, 8x9. 
Exposed area of one strip, \3/4\x7.
Filter = Total area of one strip, \3/4\x8.
Fb = Lead concentration of blank filter, [micro]g, from 
section 6.1.1.2.3.
VSTP = Air volume from section 10.1.

    11. Quality control.
    \3/4\x8 glass fiber filter strips containing 
80 to 2000 [micro]g Pb/strip (as lead salts) and blank strips with zero 
Pb content should be used to determine if the method--as being used--has 
any bias. Quality control charts should be established to monitor 
differences between measured and true values. The frequency of such 
checks will depend on the local quality control program.
    To minimize the possibility of generating unreliable data, the user 
should follow practices established for assuring the quality of air 
pollution data, (13) and take part in EPA's semiannual audit program for 
lead analyses.
    12. Trouble shooting.
    1. During extraction of lead by the hot extraction procedure, it is 
important to keep the sample covered so that corrosion products--formed 
on fume hood surfaces which may contain lead--are not deposited in the 
extract.
    2. The sample acid concentration should minimize corrosion of the 
nebulizer. However, different nebulizers may require lower acid 
concentrations. Lower concentrations can be used provided samples and 
standards have the same acid concentration.
    3. Ashing of particulate samples has been found, by EPA and 
contractor laboratories, to be unnecessary in lead analyses by atomic 
absorption. Therefore, this step was omitted from the method.
    4. Filtration of extracted samples, to remove particulate matter, 
was specifically excluded from sample preparation, because some analysts 
have observed losses of lead due to filtration.
    5. If suspended solids should clog the nebulizer during analysis of 
samples, centrifuge the sample to remove the solids.
    13. Authority.
    (Secs. 109 and 301(a), Clean Air Act, as amended (42 U.S.C. 7409, 
7601(a)))
    14. References.
    1. Scott, D. R. et al. ``Atomic Absorption and Optical Emission 
Analysis of NASN Atmospheric Particulate Samples for Lead.'' Envir. Sci. 
and Tech., 10, 877-880 (1976).
    2. Skogerboe, R. K. et al. ``Monitoring for Lead in the 
Environment.'' pp. 57-66, Department of Chemistry, Colorado State 
University, Fort Collins, CO 80523. Submitted to National Science 
Foundation for publications, 1976.
    3. Zdrojewski, A. et al. ``The Accurate Measurement of Lead in 
Airborne Particulates.'' Inter. J. Environ. Anal. Chem., 2, 63-77 
(1972).
    4. Slavin, W., ``Atomic Absorption Spectroscopy.'' Published by 
Interscience Company, New York, NY (1968).
    5. Kirkbright, G. F., and Sargent, M., ``Atomic Absorption and 
Fluorescence Spectroscopy.'' Published by Academic Press, New York, NY 
1974.
    6. Burnham, C. D. et al., ``Determination of Lead in Airborne 
Particulates in Chicago and Cook County, IL, by Atomic Absorption 
Spectroscopy.'' Envir. Sci. and Tech., 3, 472-475 (1969).
    7. ``Proposed Recommended Practices for Atomic Absorption 
Spectrometry.'' ASTM Book of Standards, part 30, pp. 1596-1608 (July 
1973).
    8. Koirttyohann, S. R. and Wen, J. W., ``Critical Study of the APCD-
MIBK Extraction System for Atomic Absorption.'' Anal. Chem., 45, 1986-
1989 (1973).
    9. Collaborative Study of Reference Method for the Determination of 
Suspended Particulates in the Atmosphere (High Volume Method). 
Obtainable from National Technical Information Service, Department of 
Commerce, Port Royal Road, Springfield, VA 22151, as PB-205-891.
    10. Intersociety Committee (1972). Methods of Air Sampling and 
Analysis. 1015 Eighteenth Street, N.W. Washington, D.C.: American Public 
Health Association. 365-372.
    11. Dubois, L., et al., ``The Metal Content of Urban Air.'' JAPCA, 
16, 77-78 (1966).
    12. EPA Report No. 600/4-77-034, June 1977, ``Los Angeles Catalyst 
Study Symposium.'' Page 223.
    13. Quality Assurance Handbook for Air Pollution Measurement System. 
Volume 1--Principles. EPA-600/9-76-005, March 1976.
    14. Thompson, R. J. et al., ``Analysis of Selected Elements in 
Atmospheric Particulate Matter by Atomic Absorption.'' Atomic Absorption 
Newsletter, 9, No. 3, May-June 1970.
    15. Sharon J. Long, et al., ``Lead Analysis of Ambient Air 
Particulates: Interlaboratory

[[Page 64]]

Evaluation of EPA Lead Reference Method'' APCA Journal, 29, 28-31 
(1979).
    16. Quality Assurance Handbook for Air Pollution Measurement 
Systems. Volume II--Ambient Air Specific Methods. EPA-600/4-77/027a, May 
1977.



[[Page 65]]





(Secs. 109, 301(a) of the Clean Air Act, as amended (42 U.S.C. 7409, 
7601(a)); secs. 110, 301(a) and 319 of the Clean Air Act (42 U.S.C. 
7410, 7601(a), 7619))

[43 FR 46258, Oct. 5, 1978; 44 FR 37915, June 29, 1979, as amended at 46 
FR 44163, Sept. 3, 1981; 52 FR 24664, July 1, 1987; 73 FR 67052, Nov. 
12, 2008]



  Sec. Appendix H to Part 50--Interpretation of the 1-Hour Primary and 
       Secondary National Ambient Air Quality Standards for Ozone

                               1. General

    This appendix explains how to determine when the expected number of 
days per calendar year with maximum hourly average concentrations above 
0.12 ppm (235 [micro]g/m\3\) is equal to or less than 1. An expanded 
discussion of these procedures and associated examples are contained in 
the ``Guideline for Interpretation of Ozone Air Quality Standards.'' For 
purposes of clarity in the following discussion, it is convenient to use 
the term ``exceedance'' to describe a daily maximum hourly average ozone 
measurement that is greater than the level of the standard. Therefore, 
the phrase ``expected number of days with maximum hourly average ozone 
concentrations above the level of the standard'' may be simply stated as 
the ``expected number of exceedances.''

[[Page 66]]

    The basic principle in making this determination is relatively 
straightforward. Most of the complications that arise in determining the 
expected number of annual exceedances relate to accounting for 
incomplete sampling. In general, the average number of exceedances per 
calendar year must be less than or equal to 1. In its simplest form, the 
number of exceedances at a monitoring site would be recorded for each 
calendar year and then averaged over the past 3 calendar years to 
determine if this average is less than or equal to 1.

                2. Interpretation of Expected Exceedances

    The ozone standard states that the expected number of exceedances 
per year must be less than or equal to 1. The statistical term 
``expected number'' is basically an arithmetic average. The following 
example explains what it would mean for an area to be in compliance with 
this type of standard. Suppose a monitoring station records a valid 
daily maximum hourly average ozone value for every day of the year 
during the past 3 years. At the end of each year, the number of days 
with maximum hourly concentrations above 0.12 ppm is determined and this 
number is averaged with the results of previous years. As long as this 
average remains ``less than or equal to 1,'' the area is in compliance.

           3. Estimating the Number of Exceedances for a Year

    In general, a valid daily maximum hourly average value may not be 
available for each day of the year, and it will be necessary to account 
for these missing values when estimating the number of exceedances for a 
particular calendar year. The purpose of these computations is to 
determine if the expected number of exceedances per year is less than or 
equal to 1. Thus, if a site has two or more observed exceedances each 
year, the standard is not met and it is not necessary to use the 
procedures of this section to account for incomplete sampling.
    The term ``missing value'' is used here in the general sense to 
describe all days that do not have an associated ozone measurement. In 
some cases, a measurement might actually have been missed but in other 
cases no measurement may have been scheduled for that day. A daily 
maximum ozone value is defined to be the highest hourly ozone value 
recorded for the day. This daily maximum value is considered to be valid 
if 75 percent of the hours from 9:01 a.m. to 9:00 p.m. (LST) were 
measured or if the highest hour is greater than the level of the 
standard.
    In some areas, the seasonal pattern of ozone is so pronounced that 
entire months need not be sampled because it is extremely unlikely that 
the standard would be exceeded. Any such waiver of the ozone monitoring 
requirement would be handled under provisions of 40 CFR, part 58. Some 
allowance should also be made for days for which valid daily maximum 
hourly values were not obtained but which would quite likely have been 
below the standard. Such an allowance introduces a complication in that 
it becomes necessary to define under what conditions a missing value may 
be assumed to have been less than the level of the standard. The 
following criterion may be used for ozone:
    A missing daily maximum ozone value may be assumed to be less than 
the level of the standard if the valid daily maxima on both the 
preceding day and the following day do not exceed 75 percent of the 
level of the standard.
    Let z denote the number of missing daily maximum values that may be 
assumed to be less than the standard. Then the following formula shall 
be used to estimate the expected number of exceedances for the year:
[GRAPHIC] [TIFF OMITTED] TC08NO91.086

    (*Indicates multiplication.)

where:

e = the estimated number of exceedances for the year,
N = the number of required monitoring days in the year,
n = the number of valid daily maxima,
v = the number of daily values above the level of the standard, and
z = the number of days assumed to be less than the standard level.

    This estimated number of exceedances shall be rounded to one decimal 
place (fractional parts equal to 0.05 round up).
    It should be noted that N will be the total number of days in the 
year unless the appropriate Regional Administrator has granted a waiver 
under the provisions of 40 CFR part 58.
    The above equation may be interpreted intuitively in the following 
manner. The estimated number of exceedances is equal to the observed 
number of exceedances (v) plus an increment that accounts for incomplete 
sampling. There were (N-n) missing values for the year but a certain 
number of these, namely z, were assumed to be less than the standard. 
Therefore, (N-n-z) missing values are considered to include possible 
exceedances. The fraction of measured values that are above the level of 
the standard is v/n. It is assumed that this same fraction applies to 
the (N-n-z) missing values and that (v/n)*(N-n-z) of these values would 
also have exceeded the level of the standard.

[44 FR 8220, Feb. 8, 1979, as amended at 62 FR 38895, July 18, 1997]

[[Page 67]]



  Sec. Appendix I to Part 50--Interpretation of the 8-Hour Primary and 
       Secondary National Ambient Air Quality Standards for Ozone

    1. General.
    This appendix explains the data handling conventions and 
computations necessary for determining whether the national 8-hour 
primary and secondary ambient air quality standards for ozone specified 
in Sec. 50.10 are met at an ambient ozone air quality monitoring site. 
Ozone is measured in the ambient air by a reference method based on 
appendix D of this part. Data reporting, data handling, and computation 
procedures to be used in making comparisons between reported ozone 
concentrations and the level of the ozone standard are specified in the 
following sections. Whether to exclude, retain, or make adjustments to 
the data affected by stratospheric ozone intrusion or other natural 
events is subject to the approval of the appropriate Regional 
Administrator.
    2. Primary and Secondary Ambient Air Quality Standards for Ozone.
    2.1 Data Reporting and Handling Conventions.
    2.1.1 Computing 8-hour averages. Hourly average concentrations shall 
be reported in parts per million (ppm) to the third decimal place, with 
additional digits to the right being truncated. Running 8-hour averages 
shall be computed from the hourly ozone concentration data for each hour 
of the year and the result shall be stored in the first, or start, hour 
of the 8-hour period. An 8-hour average shall be considered valid if at 
least 75% of the hourly averages for the 8-hour period are available. In 
the event that only 6 (or 7) hourly averages are available, the 8-hour 
average shall be computed on the basis of the hours available using 6 
(or 7) as the divisor. (8-hour periods with three or more missing hours 
shall not be ignored if, after substituting one-half the minimum 
detectable limit for the missing hourly concentrations, the 8-hour 
average concentration is greater than the level of the standard.) The 
computed 8-hour average ozone concentrations shall be reported to three 
decimal places (the insignificant digits to the right of the third 
decimal place are truncated, consistent with the data handling 
procedures for the reported data.)
    2.1.2 Daily maximum 8-hour average concentrations. (a) There are 24 
possible running 8-hour average ozone concentrations for each calendar 
day during the ozone monitoring season. (Ozone monitoring seasons vary 
by geographic location as designated in part 58, appendix D to this 
chapter.) The daily maximum 8-hour concentration for a given calendar 
day is the highest of the 24 possible 8-hour average concentrations 
computed for that day. This process is repeated, yielding a daily 
maximum 8-hour average ozone concentration for each calendar day with 
ambient ozone monitoring data. Because the 8-hour averages are recorded 
in the start hour, the daily maximum 8-hour concentrations from two 
consecutive days may have some hourly concentrations in common. 
Generally, overlapping daily maximum 8-hour averages are not likely, 
except in those non-urban monitoring locations with less pronounced 
diurnal variation in hourly concentrations.
    (b) An ozone monitoring day shall be counted as a valid day if valid 
8-hour averages are available for at least 75% of possible hours in the 
day (i.e., at least 18 of the 24 averages). In the event that less than 
75% of the 8-hour averages are available, a day shall also be counted as 
a valid day if the daily maximum 8-hour average concentration for that 
day is greater than the level of the ambient standard.
    2.2 Primary and Secondary Standard-related Summary Statistic. The 
standard-related summary statistic is the annual fourth-highest daily 
maximum 8-hour ozone concentration, expressed in parts per million, 
averaged over three years. The 3-year average shall be computed using 
the three most recent, consecutive calendar years of monitoring data 
meeting the data completeness requirements described in this appendix. 
The computed 3-year average of the annual fourth-highest daily maximum 
8-hour average ozone concentrations shall be expressed to three decimal 
places (the remaining digits to the right are truncated.)
    2.3 Comparisons with the Primary and Secondary Ozone Standards. (a) 
The primary and secondary ozone ambient air quality standards are met at 
an ambient air quality monitoring site when the 3-year average of the 
annual fourth-highest daily maximum 8-hour average ozone concentration 
is less than or equal to 0.08 ppm. The number of significant figures in 
the level of the standard dictates the rounding convention for comparing 
the computed 3-year average annual fourth-highest daily maximum 8-hour 
average ozone concentration with the level of the standard. The third 
decimal place of the computed value is rounded, with values equal to or 
greater than 5 rounding up. Thus, a computed 3-year average ozone 
concentration of 0.085 ppm is the smallest value that is greater than 
0.08 ppm.
    (b) This comparison shall be based on three consecutive, complete 
calendar years of air quality monitoring data. This requirement is met 
for the three year period at a monitoring site if daily maximum 8-hour 
average concentrations are available for at least 90%, on average, of 
the days during the designated ozone monitoring season, with a minimum 
data completeness in any one year of at least 75% of the designated 
sampling days. When

[[Page 68]]

computing whether the minimum data completeness requirements have been 
met, meteorological or ambient data may be sufficient to demonstrate 
that meteorological conditions on missing days were not conducive to 
concentrations above the level of the standard. Missing days assumed 
less than the level of the standard are counted for the purpose of 
meeting the data completeness requirement, subject to the approval of 
the appropriate Regional Administrator.
    (c) Years with concentrations greater than the level of the standard 
shall not be ignored on the ground that they have less than complete 
data. Thus, in computing the 3-year average fourth maximum 
concentration, calendar years with less than 75% data completeness shall 
be included in the computation if the average annual fourth maximum 8-
hour concentration is greater than the level of the standard.
    (d) Comparisons with the primary and secondary ozone standards are 
demonstrated by examples 1 and 2 in paragraphs (d)(1) and (d) (2) 
respectively as follows:
    (1) As shown in example 1, the primary and secondary standards are 
met at this monitoring site because the 3-year average of the annual 
fourth-highest daily maximum 8-hour average ozone concentrations (i.e., 
0.084 ppm) is less than or equal to 0.08 ppm. The data completeness 
requirement is also met because the average percent of days with valid 
ambient monitoring data is greater than 90%, and no single year has less 
than 75% data completeness.

             Example 1. Ambient monitoring site attaining the primary and secondary ozone standards
----------------------------------------------------------------------------------------------------------------
                                                 1st Highest  2nd Highest  3rd Highest  4th Highest  5th Highest
                                      Percent    Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8-
               Year                  Valid Days   hour Conc.   hour Conc.   hour Conc.   hour Conc.   hour Conc.
                                                    (ppm)        (ppm)        (ppm)        (ppm)        (ppm)
----------------------------------------------------------------------------------------------------------------
1993..............................         100%        0.092        0.091        0.090        0.088        0.085
----------------------------------------------------------------------------------------------------------------
1994..............................          96%        0.090        0.089        0.086        0.084        0.080
----------------------------------------------------------------------------------------------------------------
1995..............................          98%        0.087        0.085        0.083        0.080        0.075
================================================================================================================
    Average.......................          98%
----------------------------------------------------------------------------------------------------------------

    (2) As shown in example 2, the primary and secondary standards are 
not met at this monitoring site because the 3-year average of the 
fourth-highest daily maximum 8-hour average ozone concentrations (i.e., 
0.093 ppm) is greater than 0.08 ppm. Note that the ozone concentration 
data for 1994 is used in these computations, even though the data 
capture is less than 75%, because the average fourth-highest daily 
maximum 8-hour average concentration is greater than 0.08 ppm.

          Example 2. Ambient Monitoring Site Failing to Meet the Primary and Secondary Ozone Standards
----------------------------------------------------------------------------------------------------------------
                                                 1st Highest  2nd Highest  3rd Highest  4th Highest  5th Highest
                                      Percent    Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8-
               Year                  Valid Days   hour Conc.   hour Conc.   hour Conc.   hour Conc.   hour Conc.
                                                    (ppm)        (ppm)        (ppm)        (ppm)        (ppm)
----------------------------------------------------------------------------------------------------------------
1993..............................          96%        0.105        0.103        0.103        0.102        0.102
----------------------------------------------------------------------------------------------------------------
1994..............................          74%        0.090        0.085        0.082        0.080        0.078
----------------------------------------------------------------------------------------------------------------
1995..............................          98%        0.103        0.101        0.101        0.097        0.095
================================================================================================================
    Average.......................          89%
----------------------------------------------------------------------------------------------------------------

    3. Design Values for Primary and Secondary Ambient Air Quality 
Standards for Ozone. The air quality design value at a monitoring site 
is defined as that concentration that when reduced to the level of the 
standard ensures that the site meets the standard. For a concentration-
based standard, the air quality design value is simply the standard-
related test statistic. Thus, for the primary and secondary ozone 
standards, the 3-year average annual fourth-highest daily maximum 8-hour 
average ozone concentration is also the air quality design value for the 
site.

[62 FR 38895, July 18, 1997]



 Sec. Appendix J to Part 50--Reference Method for the Determination of 
         Particulate Matter as PM10 in the Atmosphere

    1.0 Applicability.

[[Page 69]]

    1.1 This method provides for the measurement of the mass 
concentration of particulate matter with an aerodynamic diameter less 
than or equal to a nominal 10 micrometers (PM1O) in ambient 
air over a 24-hour period for purposes of determining attainment and 
maintenance of the primary and secondary national ambient air quality 
standards for particulate matter specified in Sec. 50.6 of this 
chapter. The measurement process is nondestructive, and the 
PM10 sample can be subjected to subsequent physical or 
chemical analyses. Quality assurance procedures and guidance are 
provided in part 58, appendices A and B, of this chapter and in 
References 1 and 2.
    2.0 Principle.
    2.1 An air sampler draws ambient air at a constant flow rate into a 
specially shaped inlet where the suspended particulate matter is 
inertially separated into one or more size fractions within the 
PM10 size range. Each size fraction in the PM1O 
size range is then collected on a separate filter over the specified 
sampling period. The particle size discrimination characteristics 
(sampling effectiveness and 50 percent cutpoint) of the sampler inlet 
are prescribed as performance specifications in part 53 of this chapter.
    2.2 Each filter is weighed (after moisture equilibration) before and 
after use to determine the net weight (mass) gain due to collected 
PM10. The total volume of air sampled, corrected to EPA 
reference conditions (25 C, 101.3 kPa), is determined from the measured 
flow rate and the sampling time. The mass concentration of 
PM10 in the ambient air is computed as the total mass of 
collected particles in the PM10 size range divided by the 
volume of air sampled, and is expressed in micrograms per standard cubic 
meter ([micro]g/std m\3\). For PM10 samples collected at 
temperatures and pressures significantly different from EPA reference 
conditions, these corrected concentrations sometimes differ 
substantially from actual concentrations (in micrograms per actual cubic 
meter), particularly at high elevations. Although not required, the 
actual PM10 concentration can be calculated from the 
corrected concentration, using the average ambient temperature and 
barometric pressure during the sampling period.
    2.3 A method based on this principle will be considered a reference 
method only if (a) the associated sampler meets the requirements 
specified in this appendix and the requirements in part 53 of this 
chapter, and (b) the method has been designated as a reference method in 
accordance with part 53 of this chapter.
    3.0 Range.
    3.1 The lower limit of the mass concentration range is determined by 
the repeatability of filter tare weights, assuming the nominal air 
sample volume for the sampler. For samplers having an automatic filter-
changing mechanism, there may be no upper limit. For samplers that do 
not have an automatic filter-changing mechanism, the upper limit is 
determined by the filter mass loading beyond which the sampler no longer 
maintains the operating flow rate within specified limits due to 
increased pressure drop across the loaded filter. This upper limit 
cannot be specified precisely because it is a complex function of the 
ambient particle size distribution and type, humidity, filter type, and 
perhaps other factors. Nevertheless, all samplers should be capable of 
measuring 24-hour PM10 mass concentrations of at least 300 
[micro]g/std m\3\ while maintaining the operating flow rate within the 
specified limits.
    4.0 Precision.
    4.1 The precision of PM10 samplers must be 5 [micro]g/
m\3\ for PM10 concentrations below 80 [micro]g/m\3\ and 7 
percent for PM10 concentrations above 80 [micro]g/m\3\, as 
required by part 53 of this chapter, which prescribes a test procedure 
that determines the variation in the PM10 concentration 
measurements of identical samplers under typical sampling conditions. 
Continual assessment of precision via collocated samplers is required by 
part 58 of this chapter for PM10 samplers used in certain 
monitoring networks.
    5.0 Accuracy.
    5.1 Because the size of the particles making up ambient particulate 
matter varies over a wide range and the concentration of particles 
varies with particle size, it is difficult to define the absolute 
accuracy of PM10 samplers. Part 53 of this chapter provides a 
specification for the sampling effectiveness of PM10 
samplers. This specification requires that the expected mass 
concentration calculated for a candidate PM10 sampler, when 
sampling a specified particle size distribution, be within 10 percent of that calculated for an ideal sampler whose 
sampling effectiveness is explicitly specified. Also, the particle size 
for 50 percent sampling effectivensss is required to be 10 0.5 micrometers. Other specifications related to 
accuracy apply to flow measurement and calibration, filter media, 
analytical (weighing) procedures, and artifact. The flow rate accuracy 
of PM10 samplers used in certain monitoring networks is 
required by part 58 of this chapter to be assessed periodically via flow 
rate audits.
    6.0 Potential Sources of Error.
    6.1 Volatile Particles. Volatile particles collected on filters are 
often lost during shipment and/or storage of the filters prior to the 
post-sampling weighing \3\. Although shipment or storage of loaded 
filters is sometimes unavoidable, filters should be reweighed as soon as 
practical to minimize these losses.
    6.2 Artifacts. Positive errors in PM10 concentration 
measurements may result from retention of gaseous species on filters. 
\4,5\ Such errors include the retention of sulfur

[[Page 70]]

dioxide and nitric acid. Retention of sulfur dioxide on filters, 
followed by oxidation to sulfate, is referred to as artifact sulfate 
formation, a phenomenon which increases with increasing filter 
alkalinity. \6\ Little or no artifact sulfate formation should occur 
using filters that meet the alkalinity specification in section 7.2.4. 
Artifact nitrate formation, resulting primarily from retention of nitric 
acid, occurs to varying degrees on many filter types, including glass 
fiber, cellulose ester, and many quartz fiber filters. \5,7,8,9,10\ Loss 
of true atmospheric particulate nitrate during or following sampling may 
also occur due to dissociation or chemical reaction. This phenomenon has 
been observed on Teflon [reg] filters \8\ and inferred for 
quartz fiber filters. \11,12\ The magnitude of nitrate artifact errors 
in PM10 mass concentration measurements will vary with 
location and ambient temperature; however, for most sampling locations, 
these errors are expected to be small.
    6.3 Humidity. The effects of ambient humidity on the sample are 
unavoidable. The filter equilibration procedure in section 9.0 is 
designed to minimize the effects of moisture on the filter medium.
    6.4 Filter Handling. Careful handling of filters between presampling 
and postsampling weighings is necessary to avoid errors due to damaged 
filters or loss of collected particles from the filters. Use of a filter 
cartridge or cassette may reduce the magnitude of these errors. Filters 
must also meet the integrity specification in section 7.2.3.
    6.5 Flow Rate Variation. Variations in the sampler's operating flow 
rate may alter the particle size discrimination characteristics of the 
sampler inlet. The magnitude of this error will depend on the 
sensitivity of the inlet to variations in flow rate and on the particle 
distribution in the atmosphere during the sampling period. The use of a 
flow control device (section 7.1.3) is required to minimize this error.
    6.6 Air Volume Determination. Errors in the air volume determination 
may result from errors in the flow rate and/or sampling time 
measurements. The flow control device serves to minimize errors in the 
flow rate determination, and an elapsed time meter (section 7.1.5) is 
required to minimize the error in the sampling time measurement.
    7.0 Apparatus.
    7.1 PM10 Sampler.
    7.1.1 The sampler shall be designed to:
    a. Draw the air sample into the sampler inlet and through the 
particle collection filter at a uniform face velocity.
    b. Hold and seal the filter in a horizontal position so that sample 
air is drawn downward through the filter.
    c. Allow the filter to be installed and removed conveniently.
    d. Protect the filter and sampler from precipitation and prevent 
insects and other debris from being sampled.
    e. Minimize air leaks that would cause error in the measurement of 
the air volume passing through the filter.
    f. Discharge exhaust air at a sufficient distance from the sampler 
inlet to minimize the sampling of exhaust air.
    g. Minimize the collection of dust from the supporting surface.
    7.1.2 The sampler shall have a sample air inlet system that, when 
operated within a specified flow rate range, provides particle size 
discrimination characteristics meeting all of the applicable performance 
specifications prescribed in part 53 of this chapter. The sampler inlet 
shall show no significant wind direction dependence. The latter 
requirement can generally be satisfied by an inlet shape that is 
circularly symmetrical about a vertical axis.
    7.1.3 The sampler shall have a flow control device capable of 
maintaining the sampler's operating flow rate within the flow rate 
limits specified for the sampler inlet over normal variations in line 
voltage and filter pressure drop.
    7.1.4 The sampler shall provide a means to measure the total flow 
rate during the sampling period. A continuous flow recorder is 
recommended but not required. The flow measurement device shall be 
accurate to 2 percent.
    7.1.5 A timing/control device capable of starting and stopping the 
sampler shall be used to obtain a sample collection period of 24 1 hr (1,440 60 min). An elapsed 
time meter, accurate to within 15 minutes, shall 
be used to measure sampling time. This meter is optional for samplers 
with continuous flow recorders if the sampling time measurement obtained 
by means of the recorder meets the 15 minute 
accuracy specification.
    7.1.6 The sampler shall have an associated operation or instruction 
manual as required by part 53 of this chapter which includes detailed 
instructions on the calibration, operation, and maintenance of the 
sampler.
    7.2 Filters.
    7.2.1 Filter Medium. No commercially available filter medium is 
ideal in all respects for all samplers. The user's goals in sampling 
determine the relative importance of various filter characteristics 
(e.g., cost, ease of handling, physical and chemical characteristics, 
etc.) and, consequently, determine the choice among acceptable filters. 
Furthermore, certain types of filters may not be suitable for use with 
some samplers, particularly under heavy loading conditions (high mass 
concentrations), because of high or rapid increase in the filter flow 
resistance that would exceed the capability of the sampler's flow 
control device. However, samplers equipped with automatic filter-
changing

[[Page 71]]

mechanisms may allow use of these types of filters. The specifications 
given below are minimum requirements to ensure acceptability of the 
filter medium for measurement of PM10 mass concentrations. 
Other filter evaluation criteria should be considered to meet individual 
sampling and analysis objectives.
    7.2.2 Collection Efficiency. =99 percent, as measured by 
the DOP test (ASTM-2986) with 0.3 [micro]m particles at the sampler's 
operating face velocity.
    7.2.3 Integrity. 5 [micro]g/m\3\ (assuming 
sampler's nominal 24-hour air sample volume). Integrity is measured as 
the PM10 concentration equivalent corresponding to the 
average difference between the initial and the final weights of a random 
sample of test filters that are weighed and handled under actual or 
simulated sampling conditions, but have no air sample passed through 
them (i.e., filter blanks). As a minimum, the test procedure must 
include initial equilibration and weighing, installation on an 
inoperative sampler, removal from the sampler, and final equilibration 
and weighing.
    7.2.4 Alkalinity. <25 microequivalents/gram of filter, as measured 
by the procedure given in Reference 13 following at least two months 
storage in a clean environment (free from contamination by acidic gases) 
at room temperature and humidity.
    7.3 Flow Rate Transfer Standard. The flow rate transfer standard 
must be suitable for the sampler's operating flow rate and must be 
calibrated against a primary flow or volume standard that is traceable 
to the National Bureau of Standards (NBS). The flow rate transfer 
standard must be capable of measuring the sampler's operating flow rate 
with an accuracy of 2 percent.
    7.4 Filter Conditioning Environment.
    7.4.1 Temperature range: 15 to 30 C.
    7.4.2 Temperature control: 3 C.
    7.4.3 Humidity range: 20% to 45% RH.
    7.4.4 Humidity control: 5% RH.
    7.5 Analytical Balance. The analytical balance must be suitable for 
weighing the type and size of filters required by the sampler. The range 
and sensitivity required will depend on the filter tare weights and mass 
loadings. Typically, an analytical balance with a sensitivity of 0.1 mg 
is required for high volume samplers (flow rates 0.5 m\3\/
min). Lower volume samplers (flow rates <0.5 m\3\/min) will require a 
more sensitive balance.
    8.0 Calibration.
    8.1 General Requirements.
    8.1.1 Calibration of the sampler's flow measurement device is 
required to establish traceability of subsequent flow measurements to a 
primary standard. A flow rate transfer standard calibrated against a 
primary flow or volume standard shall be used to calibrate or verify the 
accuracy of the sampler's flow measurement device.
    8.1.2 Particle size discrimination by inertial separation requires 
that specific air velocities be maintained in the sampler's air inlet 
system. Therefore, the flow rate through the sampler's inlet must be 
maintained throughout the sampling period within the design flow rate 
range specified by the manufacturer. Design flow rates are specified as 
actual volumetric flow rates, measured at existing conditions of 
temperature and pressure (Qa). In contrast, mass 
concentrations of PM10 are computed using flow rates 
corrected to EPA reference conditions of temperature and pressure 
(Qstd).
    8.2 Flow Rate Calibration Procedure.
    8.2.1 PM10 samplers employ various types of flow control 
and flow measurement devices. The specific procedure used for flow rate 
calibration or verification will vary depending on the type of flow 
controller and flow indicator employed. Calibration in terms of actual 
volumetric flow rates (Qa) is generally recommended, but 
other measures of flow rate (e.g., Qstd) may be used provided 
the requirements of section 8.1 are met. The general procedure given 
here is based on actual volumetric flow units (Qa) and serves 
to illustrate the steps involved in the calibration of a PM10 
sampler. Consult the sampler manufacturer's instruction manual and 
Reference 2 for specific guidance on calibration. Reference 14 provides 
additional information on the use of the commonly used measures of flow 
rate and their interrelationships.
    8.2.2 Calibrate the flow rate transfer standard against a primary 
flow or volume standard traceable to NBS. Establish a calibration 
relationship (e.g., an equation or family of curves) such that 
traceability to the primary standard is accurate to within 2 percent 
over the expected range of ambient conditions (i.e., temperatures and 
pressures) under which the transfer standard will be used. Recalibrate 
the transfer standard periodically.
    8.2.3 Following the sampler manufacturer's instruction manual, 
remove the sampler inlet and connect the flow rate transfer standard to 
the sampler such that the transfer standard accurately measures the 
sampler's flow rate. Make sure there are no leaks between the transfer 
standard and the sampler.
    8.2.4 Choose a minimum of three flow rates (actual m\3\/min), spaced 
over the acceptable flow rate range specified for the inlet (see 7.1.2) 
that can be obtained by suitable adjustment of the sampler flow rate. In 
accordance with the sampler manufacturer's instruction manual, obtain or 
verify the calibration relationship between the flow rate (actual m\3\/
min) as indicated by the transfer standard and the sampler's flow 
indicator response. Record the ambient temperature and barometric 
pressure. Temperature and pressure corrections to subsequent flow 
indicator readings may be required for certain types of

[[Page 72]]

flow measurement devices. When such corrections are necessary, 
correction on an individual or daily basis is preferable. However, 
seasonal average temperature and average barometric pressure for the 
sampling site may be incorporated into the sampler calibration to avoid 
daily corrections. Consult the sampler manufacturer's instruction manual 
and Reference 2 for additional guidance.
    8.2.5 Following calibration, verify that the sampler is operating at 
its design flow rate (actual m\3\/min) with a clean filter in place.
    8.2.6 Replace the sampler inlet.
    9.0 Procedure.
    9.1 The sampler shall be operated in accordance with the specific 
guidance provided in the sampler manufacturer's instruction manual and 
in Reference 2. The general procedure given here assumes that the 
sampler's flow rate calibration is based on flow rates at ambient 
conditions (Qa) and serves to illustrate the steps involved 
in the operation of a PM10 sampler.
    9.2 Inspect each filter for pinholes, particles, and other 
imperfections. Establish a filter information record and assign an 
identification number to each filter.
    9.3 Equilibrate each filter in the conditioning environment (see 
7.4) for at least 24 hours.
    9.4 Following equilibration, weigh each filter and record the 
presampling weight with the filter identification number.
    9.5 Install a preweighed filter in the sampler following the 
instructions provided in the sampler manufacturer's instruction manual.
    9.6 Turn on the sampler and allow it to establish run-temperature 
conditions. Record the flow indicator reading and, if needed, the 
ambient temperature and barometric pressure. Determine the sampler flow 
rate (actual m\3\/min) in accordance with the instructions provided in 
the sampler manufacturer's instruction manual. NOTE.--No onsite 
temperature or pressure measurements are necessary if the sampler's flow 
indicator does not require temperature or pressure corrections or if 
seasonal average temperature and average barometric pressure for the 
sampling site are incorporated into the sampler calibration (see step 
8.2.4). If individual or daily temperature and pressure corrections are 
required, ambient temperature and barometric pressure can be obtained by 
on-site measurements or from a nearby weather station. Barometric 
pressure readings obtained from airports must be station pressure, not 
corrected to sea level, and may need to be corrected for differences in 
elevation between the sampling site and the airport.
    9.7 If the flow rate is outside the acceptable range specified by 
the manufacturer, check for leaks, and if necessary, adjust the flow 
rate to the specified setpoint. Stop the sampler.
    9.8 Set the timer to start and stop the sampler at appropriate 
times. Set the elapsed time meter to zero or record the initial meter 
reading.
    9.9 Record the sample information (site location or identification 
number, sample date, filter identification number, and sampler model and 
serial number).
    9.10 Sample for 24 1 hours.
    9.11 Determine and record the average flow rate (Qa) in 
actual m\3\/min for the sampling period in accordance with the 
instructions provided in the sampler manufacturer's instruction manual. 
Record the elapsed time meter final reading and, if needed, the average 
ambient temperature and barometric pressure for the sampling period (see 
note following step 9.6).
    9.12 Carefully remove the filter from the sampler, following the 
sampler manufacturer's instruction manual. Touch only the outer edges of 
the filter.
    9.13 Place the filter in a protective holder or container (e.g., 
petri dish, glassine envelope, or manila folder).
    9.14 Record any factors such as meteorological conditions, 
construction activity, fires or dust storms, etc., that might be 
pertinent to the measurement on the filter information record.
    9.15 Transport the exposed sample filter to the filter conditioning 
environment as soon as possible for equilibration and subsequent 
weighing.
    9.16 Equilibrate the exposed filter in the conditioning environment 
for at least 24 hours under the same temperature and humidity conditions 
used for presampling filter equilibration (see 9.3).
    9.17 Immediately after equilibration, reweigh the filter and record 
the postsampling weight with the filter identification number.
    10.0 Sampler Maintenance.
    10.1 The PM10 sampler shall be maintained in strict 
accordance with the maintenance procedures specified in the sampler 
manufacturer's instruction manual.
    11.0 Calculations.
    11.1 Calculate the average flow rate over the sampling period 
corrected to EPA reference conditions as Qstd. When the 
sampler's flow indicator is calibrated in actual volumetric units 
(Qa), Qstd is calculated as:

Qstd=Qax(Pav/
Tav)(Tstd/Pstd)

where

Qstd = average flow rate at EPA reference conditions, std 
m\3\/min;
Qa = average flow rate at ambient conditions, m\3\/min;
Pav = average barometric pressure during the sampling period 
or average barometric pressure for the sampling site, kPa (or mm Hg);
Tav = average ambient temperature during the sampling period 
or seasonal average

[[Page 73]]

ambient temperature for the sampling site, K;
Tstd = standard temperature, defined as 298 K;
Pstd = standard pressure, defined as 101.3 kPa (or 760 mm 
Hg).

    11.2 Calculate the total volume of air sampled as:

Vstd = Qstdxt

where

Vstd = total air sampled in standard volume units, std m\3\;
t = sampling time, min.

    11.3 Calculate the PM10 concentration as:

PM10 = (Wf-Wi)x10\6\/Vstd

where

PM10 = mass concentration of PM10, [micro]g/std 
m\3\;
Wf, Wi = final and initial weights of filter 
collecting PM1O particles, g;
10\6\ = conversion of g to [micro]g.

    Note: If more than one size fraction in the PM10 size 
range is collected by the sampler, the sum of the net weight gain by 
each collection filter [[Sigma](Wf-Wi)] is used to 
calculate the PM10 mass concentration.
    12.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, March 1976. Available from CERI, 
ORD Publications, U.S. Environmental Protection Agency, 26 West St. 
Clair Street, Cincinnati, OH 45268.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, May 1977. 
Available from CERI, ORD Publications, U.S. Environmental Protection 
Agency, 26 West St. Clair Street, Cincinnati, OH 45268.
    3. Clement, R.E., and F.W. Karasek. Sample Composition Changes in 
Sampling and Analysis of Organic Compounds in Aerosols. Int. J. Environ. 
Analyt. Chem., 7:109, 1979.
    4. Lee, R.E., Jr., and J. Wagman. A Sampling Anomaly in the 
Determination of Atmospheric Sulfate Concentration. Amer. Ind. Hyg. 
Assoc. J., 27:266, 1966.
    5. Appel, B.R., S.M. Wall, Y. Tokiwa, and M. Haik. Interference 
Effects in Sampling Particulate Nitrate in Ambient Air. Atmos. Environ., 
13:319, 1979.
    6. Coutant, R.W. Effect of Environmental Variables on Collection of 
Atmospheric Sulfate. Environ. Sci. Technol., 11:873, 1977.
    7. Spicer, C.W., and P. Schumacher. Interference in Sampling 
Atmospheric Particulate Nitrate. Atmos. Environ., 11:873, 1977.
    8. Appel, B.R., Y. Tokiwa, and M. Haik. Sampling of Nitrates in 
Ambient Air. Atmos. Environ., 15:283, 1981.
    9. Spicer, C.W., and P.M. Schumacher. Particulate Nitrate: 
Laboratory and Field Studies of Major Sampling Interferences. Atmos. 
Environ., 13:543, 1979.
    10. Appel, B.R. Letter to Larry Purdue, U.S. EPA, Environmental 
Monitoring and Support Laboratory. March 18, 1982, Docket No. A-82-37, 
II-I-1.
    11. Pierson, W.R., W.W. Brachaczek, T.J. Korniski, T.J. Truex, and 
J.W. Butler. Artifact Formation of Sulfate, Nitrate, and Hydrogen Ion on 
Backup Filters: Allegheny Mountain Experiment. J. Air Pollut. Control 
Assoc., 30:30, 1980.
    12. Dunwoody, C.L. Rapid Nitrate Loss From PM10 Filters. 
J. Air Pollut. Control Assoc., 36:817, 1986.
    13. Harrell, R.M. Measuring the Alkalinity of Hi-Vol Air Filters. 
EMSL/RTP-SOP-QAD-534, October 1985. Available from the U.S. 
Environmental Protection Agency, EMSL/QAD, Research Triangle Park, NC 
27711.
    14. Smith, F., P.S. Wohlschlegel, R.S.C. Rogers, and D.J. Mulligan. 
Investigation of Flow Rate Calibration Procedures Associated With the 
High Volume Method for Determination of Suspended Particulates. EPA-600/
4-78-047, U.S. Environmental Protection Agency, Research Triangle Park, 
NC 27711, 1978.

[52 FR 24664, July 1, 1987; 52 FR 29467, Aug. 7, 1987]



 Sec. Appendix K to Part 50--Interpretation of the National Ambient Air 
                Quality Standards for Particulate Matter

                               1.0 General

    (a) This appendix explains the computations necessary for analyzing 
particulate matter data to determine attainment of the 24-hour standards 
specified in 40 CFR 50.6. For the primary and secondary standards, 
particulate matter is measured in the ambient air as PM10 
(particles with an aerodynamic diameter less than or equal to a nominal 
10 micrometers) by a reference method based on appendix J of this part 
and designated in accordance with part 53 of this chapter, or by an 
equivalent method designated in accordance with part 53 of this chapter. 
The required frequency of measurements is specified in part 58 of this 
chapter.
    (b) The terms used in this appendix are defined as follows:
    Average refers to the arithmetic mean of the estimated number of 
exceedances per year, as per Section 3.1.
    Daily value for PM10 refers to the 24-hour average 
concentration of PM10 calculated or measured from midnight to 
midnight (local time).
    Exceedance means a daily value that is above the level of the 24-
hour standard after rounding to the nearest 10 [micro]g/m\3\ (i.e., 
values ending in 5 or greater are to be rounded up).

[[Page 74]]

    Expected annual value is the number approached when the annual 
values from an increasing number of years are averaged, in the absence 
of long-term trends in emissions or meteorological conditions.
    Year refers to a calendar year.
    (c) Although the discussion in this appendix focuses on monitored 
data, the same principles apply to modeling data, subject to EPA 
modeling guidelines.

                      2.0 Attainment Determinations

               2.1 24-Hour Primary and Secondary Standards

    (a) Under 40 CFR 50.6(a) the 24-hour primary and secondary standards 
are attained when the expected number of exceedances per year at each 
monitoring site is less than or equal to one. In the simplest case, the 
number of expected exceedances at a site is determined by recording the 
number of exceedances in each calendar year and then averaging them over 
the past 3 calendar years. Situations in which 3 years of data are not 
available and possible adjustments for unusual events or trends are 
discussed in sections 2.3 and 2.4 of this appendix. Further, when data 
for a year are incomplete, it is necessary to compute an estimated 
number of exceedances for that year by adjusting the observed number of 
exceedances. This procedure, performed by calendar quarter, is described 
in section 3.0 of this appendix. The expected number of exceedances is 
then estimated by averaging the individual annual estimates for the past 
3 years.
    (b) The comparison with the allowable expected exceedance rate of 
one per year is made in terms of a number rounded to the nearest tenth 
(fractional values equal to or greater than 0.05 are to be rounded up; 
e.g., an exceedance rate of 1.05 would be rounded to 1.1, which is the 
lowest rate for nonattainment).

                              2.2 Reserved

                          2.3 Data Requirements

    (a) 40 CFR 58.12 specifies the required minimum frequency of 
sampling for PM10. For the purposes of making comparisons 
with the particulate matter standards, all data produced by State and 
Local Air Monitoring Stations (SLAMS) and other sites submitted to EPA 
in accordance with the part 58 requirements must be used, and a minimum 
of 75 percent of the scheduled PM10 samples per quarter are 
required.
    (b) To demonstrate attainment of the 24-hour standards at a 
monitoring site, the monitor must provide sufficient data to perform the 
required calculations of sections 3.0 and 4.0 of this appendix. The 
amount of data required varies with the sampling frequency, data capture 
rate and the number of years of record. In all cases, 3 years of 
representative monitoring data that meet the 75 percent criterion of the 
previous paragraph should be utilized, if available, and would suffice. 
More than 3 years may be considered, if all additional representative 
years of data meeting the 75 percent criterion are utilized. Data not 
meeting these criteria may also suffice to show attainment; however, 
such exceptions will have to be approved by the appropriate Regional 
Administrator in accordance with EPA guidance.
    (c) There are less stringent data requirements for showing that a 
monitor has failed an attainment test and thus has recorded a violation 
of the particulate matter standards. Although it is generally necessary 
to meet the minimum 75 percent data capture requirement per quarter to 
use the computational equations described in section 3.0 of this 
appendix, this criterion does not apply when less data is sufficient to 
unambiguously establish nonattainment. The following examples illustrate 
how nonattainment can be demonstrated when a site fails to meet the 
completeness criteria. Nonattainment of the 24-hour primary standards 
can be established by the observed annual number of exceedances (e.g., 
four observed exceedances in a single year), or by the estimated number 
of exceedances derived from the observed number of exceedances and the 
required number of scheduled samples (e.g., two observed exceedances 
with every other day sampling). In both cases, expected annual values 
must exceed the levels allowed by the standards.

            2.4 Adjustment for Exceptional Events and Trends

    (a) An exceptional event is an uncontrollable event caused by 
natural sources of particulate matter or an event that is not expected 
to recur at a given location. Inclusion of such a value in the 
computation of exceedances or averages could result in inappropriate 
estimates of their respective expected annual values. To reduce the 
effect of unusual events, more than 3 years of representative data may 
be used. Alternatively, other techniques, such as the use of statistical 
models or the use of historical data could be considered so that the 
event may be discounted or weighted according to the likelihood that it 
will recur. The use of such techniques is subject to the approval of the 
appropriate Regional Administrator in accordance with EPA guidance.
    (b) In cases where long-term trends in emissions and air quality are 
evident, mathematical techniques should be applied to account for the 
trends to ensure that the expected annual values are not inappropriately 
biased by unrepresentative data. In the simplest case, if 3 years of 
data are available under stable emission conditions, this data should be 
used. In the event of a trend or shift in emission patterns, either the 
most

[[Page 75]]

recent representative year(s) could be used or statistical techniques or 
models could be used in conjunction with previous years of data to 
adjust for trends. The use of less than 3 years of data, and any 
adjustments are subject to the approval of the appropriate Regional 
Administrator in accordance with EPA guidance.

          3.0 Computational Equations for the 24-Hour Standards

                  3.1 Estimating Exceedances for a Year

    (a) If PM10 sampling is scheduled less frequently than 
every day, or if some scheduled samples are missed, a PM10 
value will not be available for each day of the year. To account for the 
possible effect of incomplete data, an adjustment must be made to the 
data collected at each monitoring location to estimate the number of 
exceedances in a calendar year. In this adjustment, the assumption is 
made that the fraction of missing values that would have exceeded the 
standard level is identical to the fraction of measured values above 
this level. This computation is to be made for all sites that are 
scheduled to monitor throughout the entire year and meet the minimum 
data requirements of section 2.3 of this appendix. Because of possible 
seasonal imbalance, this adjustment shall be applied on a quarterly 
basis. The estimate of the expected number of exceedances for the 
quarter is equal to the observed number of exceedances plus an increment 
associated with the missing data. The following equation must be used 
for these computations:
[GRAPHIC] [TIFF OMITTED] TR17OC06.000

Where:

eq = the estimated number of exceedances for calendar quarter 
q;
vq = the observed number of exceedances for calendar quarter 
q;
Nq = the number of days in calendar quarter q;
nq = the number of days in calendar quarter q with 
PM10 data; and
q = the index for calendar quarter, q = 1, 2, 3 or 4.

    (b) The estimated number of exceedances for a calendar quarter must 
be rounded to the nearest hundredth (fractional values equal to or 
greater than 0.005 must be rounded up).
    (c) The estimated number of exceedances for the year, e, is the sum 
of the estimates for each calendar quarter.
[GRAPHIC] [TIFF OMITTED] TR17OC06.001

    (d) The estimated number of exceedances for a single year must be 
rounded to one decimal place (fractional values equal to or greater than 
0.05 are to be rounded up). The expected number of exceedances is then 
estimated by averaging the individual annual estimates for the most 
recent 3 or more representative years of data. The expected number of 
exceedances must be rounded to one decimal place (fractional values 
equal to or greater than 0.05 are to be rounded up).
    (e) The adjustment for incomplete data will not be necessary for 
monitoring or modeling data which constitutes a complete record, i.e., 
365 days per year.
    (f) To reduce the potential for overestimating the number of 
expected exceedances, the correction for missing data will not be 
required for a calendar quarter in which the first observed exceedance 
has occurred if:
    (1) There was only one exceedance in the calendar quarter;
    (2) Everyday sampling is subsequently initiated and maintained for 4 
calendar quarters in accordance with 40 CFR 58.12; and
    (3) Data capture of 75 percent is achieved during the required 
period of everyday sampling. In addition, if the first exceedance is 
observed in a calendar quarter in which the monitor is already sampling 
every day, no adjustment for missing data will be made to the first 
exceedance if a 75 percent data capture rate was achieved in the quarter 
in which it was observed.

                                Example 1

    a. During a particular calendar quarter, 39 out of a possible 92 
samples were recorded, with one observed exceedance of the 24-hour 
standard. Using Equation 1, the estimated number of exceedances for the 
quarter is:

eq = 1 x 92/39 = 2.359 or 2.36.

    b. If the estimated exceedances for the other 3 calendar quarters in 
the year were 2.30, 0.0 and 0.0, then, using Equation 2, the estimated 
number of exceedances for the year is 2.36 + 2.30 + 0.0 + 0.0 which 
equals 4.66 or 4.7. If no exceedances were observed for the 2 previous 
years, then the expected number of exceedances is estimated by: (\1/3\) 
x (4.7 + 0 + 0) = 1.57 or 1.6. Since 1.6 exceeds the allowable number of 
expected exceedances, this monitoring site would fail the attainment 
test.

[[Page 76]]

                                Example 2

    In this example, everyday sampling was initiated following the first 
observed exceedance as required by 40 CFR 58.12. Accordingly, the first 
observed exceedance would not be adjusted for incomplete sampling. 
During the next three quarters, 1.2 exceedances were estimated. In this 
case, the estimated exceedances for the year would be 1.0 + 1.2 + 0.0 + 
0.0 which equals 2.2. If, as before, no exceedances were observed for 
the two previous years, then the estimated exceedances for the 3-year 
period would then be (\1/3\) x (2.2 + 0.0 + 0.0) = 0.7, and the 
monitoring site would not fail the attainment test.

             3.2 Adjustments for Non-Scheduled Sampling Days

    (a) If a systematic sampling schedule is used and sampling is 
performed on days in addition to the days specified by the systematic 
sampling schedule, e.g., during episodes of high pollution, then an 
adjustment must be made in the equation for the estimation of 
exceedances. Such an adjustment is needed to eliminate the bias in the 
estimate of the quarterly and annual number of exceedances that would 
occur if the chance of an exceedance is different for scheduled than for 
non-scheduled days, as would be the case with episode sampling.
    (b) The required adjustment treats the systematic sampling schedule 
as a stratified sampling plan. If the period from one scheduled sample 
until the day preceding the next scheduled sample is defined as a 
sampling stratum, then there is one stratum for each scheduled sampling 
day. An average number of observed exceedances is computed for each of 
these sampling strata. With nonscheduled sampling days, the estimated 
number of exceedances is defined as:
[GRAPHIC] [TIFF OMITTED] TR17OC06.002

Where:

eq = the estimated number of exceedances for the quarter;
Nq = the number of days in the quarter;
mq = the number of strata with samples during the quarter;
vj = the number of observed exceedances in stratum j; and
kj = the number of actual samples in stratum j.

    (c) Note that if only one sample value is recorded in each stratum, 
then Equation 3 reduces to Equation 1.

                                Example 3

    A monitoring site samples according to a systematic sampling 
schedule of one sample every 6 days, for a total of 15 scheduled samples 
in a quarter out of a total of 92 possible samples. During one 6-day 
period, potential episode levels of PM10 were suspected, so 5 
additional samples were taken. One of the regular scheduled samples was 
missed, so a total of 19 samples in 14 sampling strata were measured. 
The one 6-day sampling stratum with 6 samples recorded 2 exceedances. 
The remainder of the quarter with one sample per stratum recorded zero 
exceedances. Using Equation 3, the estimated number of exceedances for 
the quarter is:

    Eq = (92/14) x (2/6 + 0 +. . .+ 0) = 2.19.

[71 FR 61224, Oct. 17, 2006]



 Sec. Appendix L to Part 50--Reference Method for the Determination of 
      Fine Particulate Matter as PM2.5 in the Atmosphere

    1.0 Applicability.
    1.1 This method provides for the measurement of the mass 
concentration of fine particulate matter having an aerodynamic diameter 
less than or equal to a nominal 2.5 micrometers (PM2.5) in 
ambient air over a 24-hour period for purposes of determining whether 
the primary and secondary national ambient air quality standards for 
fine particulate matter specified in Sec. 50.7 and Sec. 50.13 of this 
part are met. The measurement process is considered to be 
nondestructive, and the PM2.5 sample obtained can be 
subjected to subsequent physical or chemical analyses. Quality 
assessment procedures are provided in part 58, appendix A of this 
chapter, and quality assurance guidance are provided in references 1, 2, 
and 3 in section 13.0 of this appendix.
    1.2 This method will be considered a reference method for purposes 
of part 58 of this chapter only if:
    (a) The associated sampler meets the requirements specified in this 
appendix and the applicable requirements in part 53 of this chapter, and
    (b) The method and associated sampler have been designated as a 
reference method in accordance with part 53 of this chapter.
    1.3 PM2.5 samplers that meet nearly all specifications 
set forth in this method but have minor deviations and/or modifications 
of the reference method sampler will be designated as ``Class I'' 
equivalent methods for PM2.5 in accordance with part 53 of 
this chapter.
    2.0 Principle.
    2.1 An electrically powered air sampler draws ambient air at a 
constant volumetric flow rate into a specially shaped inlet and through 
an inertial particle size separator

[[Page 77]]

(impactor) where the suspended particulate matter in the 
PM2.5 size range is separated for collection on a 
polytetrafluoroethylene (PTFE) filter over the specified sampling 
period. The air sampler and other aspects of this reference method are 
specified either explicitly in this appendix or generally with reference 
to other applicable regulations or quality assurance guidance.
    2.2 Each filter is weighed (after moisture and temperature 
conditioning) before and after sample collection to determine the net 
gain due to collected PM2.5. The total volume of air sampled 
is determined by the sampler from the measured flow rate at actual 
ambient temperature and pressure and the sampling time. The mass 
concentration of PM2.5 in the ambient air is computed as the 
total mass of collected particles in the PM2.5 size range 
divided by the actual volume of air sampled, and is expressed in 
micrograms per cubic meter of air ([micro]g/m\3\).
    3.0 PM2.5 Measurement Range.
    3.1 Lower concentration limit. The lower detection limit of the mass 
concentration measurement range is estimated to be approximately 2 
[micro]g/m\3\, based on noted mass changes in field blanks in 
conjunction with the 24 m\3\ nominal total air sample volume specified 
for the 24-hour sample.
    3.2 Upper concentration limit. The upper limit of the mass 
concentration range is determined by the filter mass loading beyond 
which the sampler can no longer maintain the operating flow rate within 
specified limits due to increased pressure drop across the loaded 
filter. This upper limit cannot be specified precisely because it is a 
complex function of the ambient particle size distribution and type, 
humidity, the individual filter used, the capacity of the sampler flow 
rate control system, and perhaps other factors. Nevertheless, all 
samplers are estimated to be capable of measuring 24-hour 
PM2.5 mass concentrations of at least 200 [micro]g/m\3\ while 
maintaining the operating flow rate within the specified limits.
    3.3 Sample period. The required sample period for PM2.5 
concentration measurements by this method shall be 1,380 to 1500 minutes 
(23 to 25 hours). However, when a sample period is less than 1,380 
minutes, the measured concentration (as determined by the collected 
PM2.5 mass divided by the actual sampled air volume), 
multiplied by the actual number of minutes in the sample period and 
divided by 1,440, may be used as if it were a valid concentration 
measurement for the specific purpose of determining a violation of the 
NAAQS. This value assumes that the PM2.5 concentration is 
zero for the remaining portion of the sample period and therefore 
represents the minimum concentration that could have been measured for 
the full 24-hour sample period. Accordingly, if the value thus 
calculated is high enough to be an exceedance, such an exceedance would 
be a valid exceedance for the sample period. When reported to AIRS, this 
data value should receive a special code to identify it as not to be 
commingled with normal concentration measurements or used for other 
purposes.
    4.0 Accuracy.
    4.1 Because the size and volatility of the particles making up 
ambient particulate matter vary over a wide range and the mass 
concentration of particles varies with particle size, it is difficult to 
define the accuracy of PM2.5 measurements in an absolute 
sense. The accuracy of PM2.5 measurements is therefore 
defined in a relative sense, referenced to measurements provided by this 
reference method. Accordingly, accuracy shall be defined as the degree 
of agreement between a subject field PM2.5 sampler and a 
collocated PM2.5 reference method audit sampler operating 
simultaneously at the monitoring site location of the subject sampler 
and includes both random (precision) and systematic (bias) errors. The 
requirements for this field sampler audit procedure are set forth in 
part 58, appendix A of this chapter.
    4.2 Measurement system bias. Results of collocated measurements 
where the duplicate sampler is a reference method sampler are used to 
assess a portion of the measurement system bias according to the 
schedule and procedure specified in part 58, appendix A of this chapter.
    4.3 Audits with reference method samplers to determine system 
accuracy and bias. According to the schedule and procedure specified in 
part 58, appendix A of this chapter, a reference method sampler is 
required to be located at each of selected PM2.5 SLAMS sites 
as a duplicate sampler. The results from the primary sampler and the 
duplicate reference method sampler are used to calculate accuracy of the 
primary sampler on a quarterly basis, bias of the primary sampler on an 
annual basis, and bias of a single reporting organization on an annual 
basis. Reference 2 in section 13.0 of this appendix provides additional 
information and guidance on these reference method audits.
    4.4 Flow rate accuracy and bias. Part 58, appendix A of this chapter 
requires that the flow rate accuracy and bias of individual 
PM2.5 samplers used in SLAMS monitoring networks be assessed 
periodically via audits of each sampler's operational flow rate. In 
addition, part 58, appendix A of this chapter requires that flow rate 
bias for each reference and equivalent method operated by each reporting 
organization be assessed quarterly and annually. Reference 2 in section 
13.0 of this appendix provides additional information and guidance on 
flow rate accuracy audits and calculations for accuracy and bias.
    5.0 Precision. A data quality objective of 10 percent coefficient of 
variation or better has

[[Page 78]]

been established for the operational precision of PM2.5 
monitoring data.
    5.1 Tests to establish initial operational precision for each 
reference method sampler are specified as a part of the requirements for 
designation as a reference method under Sec. 53.58 of this chapter.
    5.2 Measurement System Precision. Collocated sampler results, where 
the duplicate sampler is not a reference method sampler but is a sampler 
of the same designated method as the primary sampler, are used to assess 
measurement system precision according to the schedule and procedure 
specified in part 58, appendix A of this chapter. Part 58, appendix A of 
this chapter requires that these collocated sampler measurements be used 
to calculate quarterly and annual precision estimates for each primary 
sampler and for each designated method employed by each reporting 
organization. Reference 2 in section 13.0 of this appendix provides 
additional information and guidance on this requirement.
    6.0 Filter for PM2.5 Sample Collection. Any filter 
manufacturer or vendor who sells or offers to sell filters specifically 
identified for use with this PM2.5 reference method shall 
certify that the required number of filters from each lot of filters 
offered for sale as such have been tested as specified in this section 
6.0 and meet all of the following design and performance specifications.
    6.1 Size. Circular, 46.2 mm diameter 0.25 mm.
    6.2 Medium. Polytetrafluoroethylene (PTFE Teflon), with integral 
support ring.
    6.3 Support ring. Polymethylpentene (PMP) or equivalent inert 
material, 0.38 0.04 mm thick, outer diameter 46.2 
mm 0.25 mm, and width of 3.68 mm ( 0.00, -0.51 mm).
    6.4 Pore size. 2 [micro]m as measured by ASTM F 316-94.
    6.5 Filter thickness. 30 to 50 [micro]m.
    6.6 Maximum pressure drop (clean filter). 30 cm H2O 
column @ 16.67 L/min clean air flow.
    6.7 Maximum moisture pickup. Not more than 10 [micro]g weight 
increase after 24-hour exposure to air of 40 percent relative humidity, 
relative to weight after 24-hour exposure to air of 35 percent relative 
humidity.
    6.8 Collection efficiency. Greater than 99.7 percent, as measured by 
the DOP test (ASTM D 2986-91) with 0.3 [micro]m particles at the 
sampler's operating face velocity.
    6.9 Filter weight stability. Filter weight loss shall be less than 
20 [micro]g, as measured in each of the following two tests specified in 
sections 6.9.1 and 6.9.2 of this appendix. The following conditions 
apply to both of these tests: Filter weight loss shall be the average 
difference between the initial and the final filter weights of a random 
sample of test filters selected from each lot prior to sale. The number 
of filters tested shall be not less than 0.1 percent of the filters of 
each manufacturing lot, or 10 filters, whichever is greater. The filters 
shall be weighed under laboratory conditions and shall have had no air 
sample passed through them, i.e., filter blanks. Each test procedure 
must include initial conditioning and weighing, the test, and final 
conditioning and weighing. Conditioning and weighing shall be in 
accordance with sections 8.0 through 8.2 of this appendix and general 
guidance provided in reference 2 of section 13.0 of this appendix.
    6.9.1 Test for loose, surface particle contamination. After the 
initial weighing, install each test filter, in turn, in a filter 
cassette (Figures L-27, L-28, and L-29 of this appendix) and drop the 
cassette from a height of 25 cm to a flat hard surface, such as a 
particle-free wood bench. Repeat two times, for a total of three drop 
tests for each test filter. Remove the test filter from the cassette and 
weigh the filter. The average change in weight must be less than 20 
[micro]g.
    6.9.2 Test for temperature stability. After weighing each filter, 
place the test filters in a drying oven set at 40 [deg]C 2 [deg]C for not less than 48 hours. Remove, condition, 
and reweigh each test filter. The average change in weight must be less 
than 20 [micro]g.
    6.10 Alkalinity. Less than 25 microequivalents/gram of filter, as 
measured by the guidance given in reference 2 in section 13.0 of this 
appendix.
    6.11 Supplemental requirements. Although not required for 
determination of PM2.5 mass concentration under this 
reference method, additional specifications for the filter must be 
developed by users who intend to subject PM2.5 filter samples 
to subsequent chemical analysis. These supplemental specifications 
include background chemical contamination of the filter and any other 
filter parameters that may be required by the method of chemical 
analysis. All such supplemental filter specifications must be compatible 
with and secondary to the primary filter specifications given in this 
section 6.0 of this appendix.
    7.0 PM2.5 Sampler.
    7.1 Configuration. The sampler shall consist of a sample air inlet, 
downtube, particle size separator (impactor), filter holder assembly, 
air pump and flow rate control system, flow rate measurement device, 
ambient and filter temperature monitoring system, barometric pressure 
measurement system, timer, outdoor environmental enclosure, and suitable 
mechanical, electrical, or electronic control capability to meet or 
exceed the design and functional performance as specified in this 
section 7.0 of this appendix. The performance specifications require 
that the sampler:
    (a) Provide automatic control of sample volumetric flow rate and 
other operational parameters.
    (b) Monitor these operational parameters as well as ambient 
temperature and pressure.
    (c) Provide this information to the sampler operator at the end of 
each sample period in

[[Page 79]]

digital form, as specified in table L-1 of section 7.4.19 of this 
appendix.
    7.2 Nature of specifications. The PM2.5 sampler is 
specified by a combination of design and performance requirements. The 
sample inlet, downtube, particle size discriminator, filter cassette, 
and the internal configuration of the filter holder assembly are 
specified explicitly by design figures and associated mechanical 
dimensions, tolerances, materials, surface finishes, assembly 
instructions, and other necessary specifications. All other aspects of 
the sampler are specified by required operational function and 
performance, and the design of these other aspects (including the design 
of the lower portion of the filter holder assembly) is optional, subject 
to acceptable operational performance. Test procedures to demonstrate 
compliance with both the design and performance requirements are set 
forth in subpart E of part 53 of this chapter.
    7.3 Design specifications. Except as indicated in this section 7.3 
of this appendix, these components must be manufactured or reproduced 
exactly as specified, in an ISO 9001-registered facility, with 
registration initially approved and subsequently maintained during the 
period of manufacture. See Sec. 53.1(t) of this chapter for the 
definition of an ISO-registered facility. Minor modifications or 
variances to one or more components that clearly would not affect the 
aerodynamic performance of the inlet, downtube, impactor, or filter 
cassette will be considered for specific approval. Any such proposed 
modifications shall be described and submitted to the EPA for specific 
individual acceptability either as part of a reference or equivalent 
method application under part 53 of this chapter or in writing in 
advance of such an intended application under part 53 of this chapter.
    7.3.1 Sample inlet assembly. The sample inlet assembly, consisting 
of the inlet, downtube, and impactor shall be configured and assembled 
as indicated in Figure L-1 of this appendix and shall meet all 
associated requirements. A portion of this assembly shall also be 
subject to the maximum overall sampler leak rate specification under 
section 7.4.6 of this appendix.
    7.3.2 Inlet. The sample inlet shall be fabricated as indicated in 
Figures L-2 through L-18 of this appendix and shall meet all associated 
requirements.
    7.3.3 Downtube. The downtube shall be fabricated as indicated in 
Figure L-19 of this appendix and shall meet all associated requirements.
    7.3.4 Particle size separator. The sampler shall be configured with 
either one of the two alternative particle size separators described in 
this section 7.3.4. One separator is an impactor-type separator (WINS 
impactor) described in sections 7.3.4.1, 7.3.4.2, and 7.3.4.3 of this 
appendix. The alternative separator is a cyclone-type separator 
(VSCC\TM\) described in section 7.3.4.4 of this appendix.
    7.3.4.1 The impactor (particle size separator) shall be fabricated 
as indicated in Figures L-20 through L-24 of this appendix and shall 
meet all associated requirements. Following the manufacture and 
finishing of each upper impactor housing (Figure L-21 of this appendix), 
the dimension of the impaction jet must be verified by the manufacturer 
using Class ZZ go/no-go plug gauges that are traceable to NIST.
    7.3.4.2 Impactor filter specifications:
    (a) Size. Circular, 35 to 37 mm diameter.
    (b) Medium. Borosilicate glass fiber, without binder.
    (c) Pore size. 1 to 1.5 micrometer, as measured by ASTM F 316-80.
    (d) Thickness. 300 to 500 micrometers.
    7.3.4.3 Impactor oil specifications:
    (a) Composition. Dioctyl sebacate (DOS), single-compound diffusion 
oil.
    (b) Vapor pressure. Maximum 2x10-8 mm Hg at 25 [deg]C.
    (c) Viscosity. 36 to 40 centistokes at 25 [deg]C.
    (d) Density. 1.06 to 1.07 g/cm\3\ at 25 [deg]C.
    (e) Quantity. 1 mL 0.1 mL.
    7.3.4.4 The cyclone-type separator is identified as a BGI VSCC\TM\ 
Very Sharp Cut Cyclone particle size separator specified as part of EPA-
designated equivalent method EQPM-0202-142 (67 FR 15567, April 2, 2002) 
and as manufactured by BGI Incorporated, 58 Guinan Street, Waltham, 
Massachusetts 20451.
    7.3.5 Filter holder assembly. The sampler shall have a sample filter 
holder assembly to adapt and seal to the down tube and to hold and seal 
the specified filter, under section 6.0 of this appendix, in the sample 
air stream in a horizontal position below the downtube such that the 
sample air passes downward through the filter at a uniform face 
velocity. The upper portion of this assembly shall be fabricated as 
indicated in Figures L-25 and L-26 of this appendix and shall accept and 
seal with the filter cassette, which shall be fabricated as indicated in 
Figures L-27 through L-29 of this appendix.
    (a) The lower portion of the filter holder assembly shall be of a 
design and construction that:
    (1) Mates with the upper portion of the assembly to complete the 
filter holder assembly,
    (2) Completes both the external air seal and the internal filter 
cassette seal such that all seals are reliable over repeated filter 
changings, and
    (3) Facilitates repeated changing of the filter cassette by the 
sampler operator.
    (b) Leak-test performance requirements for the filter holder 
assembly are included in section 7.4.6 of this appendix.
    (c) If additional or multiple filters are stored in the sampler as 
part of an automatic sequential sample capability, all such

[[Page 80]]

filters, unless they are currently and directly installed in a sampling 
channel or sampling configuration (either active or inactive), shall be 
covered or (preferably) sealed in such a way as to:
    (1) Preclude significant exposure of the filter to possible 
contamination or accumulation of dust, insects, or other material that 
may be present in the ambient air, sampler, or sampler ventilation air 
during storage periods either before or after sampling; and
    (2) To minimize loss of volatile or semi-volatile PM sample 
components during storage of the filter following the sample period.
    7.3.6 Flow rate measurement adapter. A flow rate measurement adapter 
as specified in Figure L-30 of this appendix shall be furnished with 
each sampler.
    7.3.7 Surface finish. All internal surfaces exposed to sample air 
prior to the filter shall be treated electrolytically in a sulfuric acid 
bath to produce a clear, uniform anodized surface finish of not less 
than 1000 mg/ft\2\ (1.08 mg/cm\2\) in accordance with military standard 
specification (mil. spec.) 8625F, Type II, Class 1 in reference 4 of 
section 13.0 of this appendix. This anodic surface coating shall not be 
dyed or pigmented. Following anodization, the surfaces shall be sealed 
by immersion in boiling deionized water for not less than 15 minutes. 
Section 53.51(d)(2) of this chapter should also be consulted.
    7.3.8 Sampling height. The sampler shall be equipped with legs, a 
stand, or other means to maintain the sampler in a stable, upright 
position and such that the center of the sample air entrance to the 
inlet, during sample collection, is maintained in a horizontal plane and 
is 2.0 0.2 meters above the floor or other 
horizontal supporting surface. Suitable bolt holes, brackets, tie-downs, 
or other means should be provided to facilitate mechanically securing 
the sample to the supporting surface to prevent toppling of the sampler 
due to wind.
    7.4 Performance specifications.
    7.4.1 Sample flow rate. Proper operation of the impactor requires 
that specific air velocities be maintained through the device. 
Therefore, the design sample air flow rate through the inlet shall be 
16.67 L/min (1.000 m\3\/hour) measured as actual volumetric flow rate at 
the temperature and pressure of the sample air entering the inlet.
    7.4.2 Sample air flow rate control system. The sampler shall have a 
sample air flow rate control system which shall be capable of providing 
a sample air volumetric flow rate within the specified range, under 
section 7.4.1 of this appendix, for the specified filter, under section 
6.0 of this appendix, at any atmospheric conditions specified, under 
section 7.4.7 of this appendix, at a filter pressure drop equal to that 
of a clean filter plus up to 75 cm water column (55 mm Hg), and over the 
specified range of supply line voltage, under section 7.4.15.1 of this 
appendix. This flow control system shall allow for operator adjustment 
of the operational flow rate of the sampler over a range of at least 
15 percent of the flow rate specified in section 
7.4.1 of this appendix.
    7.4.3 Sample flow rate regulation. The sample flow rate shall be 
regulated such that for the specified filter, under section 6.0 of this 
appendix, at any atmospheric conditions specified, under section 7.4.7 
of this appendix, at a filter pressure drop equal to that of a clean 
filter plus up to 75 cm water column (55 mm Hg), and over the specified 
range of supply line voltage, under section 7.4.15.1 of this appendix, 
the flow rate is regulated as follows:
    7.4.3.1 The volumetric flow rate, measured or averaged over 
intervals of not more than 5 minutes over a 24-hour period, shall not 
vary more than 5 percent from the specified 16.67 
L/min flow rate over the entire sample period.
    7.4.3.2 The coefficient of variation (sample standard deviation 
divided by the mean) of the flow rate, measured over a 24-hour period, 
shall not be greater than 2 percent.
    7.4.3.3 The amplitude of short-term flow rate pulsations, such as 
may originate from some types of vacuum pumps, shall be attenuated such 
that they do not cause significant flow measurement error or affect the 
collection of particles on the particle collection filter.
    7.4.4 Flow rate cut off. The sampler's sample air flow rate control 
system shall terminate sample collection and stop all sample flow for 
the remainder of the sample period in the event that the sample flow 
rate deviates by more than 10 percent from the sampler design flow rate 
specified in section 7.4.1 of this appendix for more than 60 seconds. 
However, this sampler cut-off provision shall not apply during periods 
when the sampler is inoperative due to a temporary power interruption, 
and the elapsed time of the inoperative period shall not be included in 
the total sample time measured and reported by the sampler, under 
section 7.4.13 of this appendix.
    7.4.5 Flow rate measurement.
    7.4.5.1 The sampler shall provide a means to measure and indicate 
the instantaneous sample air flow rate, which shall be measured as 
volumetric flow rate at the temperature and pressure of the sample air 
entering the inlet, with an accuracy of 2 percent. 
The measured flow rate shall be available for display to the sampler 
operator at any time in either sampling or standby modes, and the 
measurement shall be updated at least every 30 seconds. The sampler 
shall also provide a simple means by which the sampler operator can 
manually start the sample flow temporarily during non-sampling modes of 
operation, for the purpose of checking the sample flow rate or the flow 
rate measurement system.
    7.4.5.2 During each sample period, the sampler's flow rate 
measurement system shall

[[Page 81]]

automatically monitor the sample volumetric flow rate, obtaining flow 
rate measurements at intervals of not greater than 30 seconds.
    (a) Using these interval flow rate measurements, the sampler shall 
determine or calculate the following flow-related parameters, scaled in 
the specified engineering units:
    (1) The instantaneous or interval-average flow rate, in L/min.
    (2) The value of the average sample flow rate for the sample period, 
in L/min.
    (3) The value of the coefficient of variation (sample standard 
deviation divided by the average) of the sample flow rate for the sample 
period, in percent.
    (4) The occurrence of any time interval during the sample period in 
which the measured sample flow rate exceeds a range of 5 percent of the average flow rate for the sample period 
for more than 5 minutes, in which case a warning flag indicator shall be 
set.
    (5) The value of the integrated total sample volume for the sample 
period, in m\3\.
    (b) Determination or calculation of these values shall properly 
exclude periods when the sampler is inoperative due to temporary 
interruption of electrical power, under section 7.4.13 of this appendix, 
or flow rate cut off, under section 7.4.4 of this appendix.
    (c) These parameters shall be accessible to the sampler operator as 
specified in table L-1 of section 7.4.19 of this appendix. In addition, 
it is strongly encouraged that the flow rate for each 5-minute interval 
during the sample period be available to the operator following the end 
of the sample period.
    7.4.6 Leak test capability.
    7.4.6.1 External leakage. The sampler shall include an external air 
leak-test capability consisting of components, accessory hardware, 
operator interface controls, a written procedure in the associated 
Operation/Instruction Manual, under section 7.4.18 of this appendix, and 
all other necessary functional capability to permit and facilitate the 
sampler operator to conveniently carry out a leak test of the sampler at 
a field monitoring site without additional equipment. The sampler 
components to be subjected to this leak test include all components and 
their interconnections in which external air leakage would or could 
cause an error in the sampler's measurement of the total volume of 
sample air that passes through the sample filter.
    (a) The suggested technique for the operator to use for this leak 
test is as follows:
    (1) Remove the sampler inlet and installs the flow rate measurement 
adapter supplied with the sampler, under section 7.3.6 of this appendix.
    (2) Close the valve on the flow rate measurement adapter and use the 
sampler air pump to draw a partial vacuum in the sampler, including (at 
least) the impactor, filter holder assembly (filter in place), flow 
measurement device, and interconnections between these devices, of at 
least 55 mm Hg (75 cm water column), measured at a location downstream 
of the filter holder assembly.
    (3) Plug the flow system downstream of these components to isolate 
the components under vacuum from the pump, such as with a built-in 
valve.
    (4) Stop the pump.
    (5) Measure the trapped vacuum in the sampler with a built-in 
pressure measuring device.
    (6) (i) Measure the vacuum in the sampler with the built-in pressure 
measuring device again at a later time at least 10 minutes after the 
first pressure measurement.
    (ii) Caution: Following completion of the test, the adaptor valve 
should be opened slowly to limit the flow rate of air into the sampler. 
Excessive air flow rate may blow oil out of the impactor.
    (7) Upon completion of the test, open the adaptor valve, remove the 
adaptor and plugs, and restore the sampler to the normal operating 
configuration.
    (b) The associated leak test procedure shall require that for 
successful passage of this test, the difference between the two pressure 
measurements shall not be greater than the number of mm of Hg specified 
for the sampler by the manufacturer, based on the actual internal volume 
of the sampler, that indicates a leak of less than 80 mL/min.
    (c) Variations of the suggested technique or an alternative external 
leak test technique may be required for samplers whose design or 
configuration would make the suggested technique impossible or 
impractical. The specific proposed external leak test procedure, or 
particularly an alternative leak test technique, proposed for a 
particular candidate sampler may be described and submitted to the EPA 
for specific individual acceptability either as part of a reference or 
equivalent method application under part 53 of this chapter or in 
writing in advance of such an intended application under part 53 of this 
chapter.
    7.4.6.2 Internal, filter bypass leakage. The sampler shall include 
an internal, filter bypass leak-check capability consisting of 
components, accessory hardware, operator interface controls, a written 
procedure in the Operation/Instruction Manual, and all other necessary 
functional capability to permit and facilitate the sampler operator to 
conveniently carry out a test for internal filter bypass leakage in the 
sampler at a field monitoring site without additional equipment. The 
purpose of the test is to determine that any portion of the sample flow 
rate that leaks past the sample filter without passing through the 
filter is insignificant relative to the design flow rate for the 
sampler.
    (a) The suggested technique for the operator to use for this leak 
test is as follows:

[[Page 82]]

    (1) Carry out an external leak test as provided under section 
7.4.6.1 of this appendix which indicates successful passage of the 
prescribed external leak test.
    (2) Install a flow-impervious membrane material in the filter 
cassette, either with or without a filter, as appropriate, which 
effectively prevents air flow through the filter.
    (3) Use the sampler air pump to draw a partial vacuum in the 
sampler, downstream of the filter holder assembly, of at least 55 mm Hg 
(75 cm water column).
    (4) Plug the flow system downstream of the filter holder to isolate 
the components under vacuum from the pump, such as with a built-in 
valve.
    (5) Stop the pump.
    (6) Measure the trapped vacuum in the sampler with a built-in 
pressure measuring device.
    (7) Measure the vacuum in the sampler with the built-in pressure 
measuring device again at a later time at least 10 minutes after the 
first pressure measurement.
    (8) Remove the flow plug and membrane and restore the sampler to the 
normal operating configuration.
    (b) The associated leak test procedure shall require that for 
successful passage of this test, the difference between the two pressure 
measurements shall not be greater than the number of mm of Hg specified 
for the sampler by the manufacturer, based on the actual internal volume 
of the portion of the sampler under vacuum, that indicates a leak of 
less than 80 mL/min.
    (c) Variations of the suggested technique or an alternative 
internal, filter bypass leak test technique may be required for samplers 
whose design or configuration would make the suggested technique 
impossible or impractical. The specific proposed internal leak test 
procedure, or particularly an alternative internal leak test technique 
proposed for a particular candidate sampler may be described and 
submitted to the EPA for specific individual acceptability either as 
part of a reference or equivalent method application under part 53 of 
this chapter or in writing in advance of such intended application under 
part 53 of this chapter.
    7.4.7 Range of operational conditions. The sampler is required to 
operate properly and meet all requirements specified in this appendix 
over the following operational ranges.
    7.4.7.1 Ambient temperature. -30 to =45 [deg]C (Note: Although for 
practical reasons, the temperature range over which samplers are 
required to be tested under part 53 of this chapter is -20 to =40 
[deg]C, the sampler shall be designed to operate properly over this 
wider temperature range.).
    7.4.7.2 Ambient relative humidity. 0 to 100 percent.
    7.4.7.3 Barometric pressure range. 600 to 800 mm Hg.
    7.4.8 Ambient temperature sensor. The sampler shall have capability 
to measure the temperature of the ambient air surrounding the sampler 
over the range of -30 to =45 [deg]C, with a resolution of 0.1 [deg]C and 
accuracy of 2.0 [deg]C, referenced as described in 
reference 3 in section 13.0 of this appendix, with and without maximum 
solar insolation.
    7.4.8.1 The ambient temperature sensor shall be mounted external to 
the sampler enclosure and shall have a passive, naturally ventilated sun 
shield. The sensor shall be located such that the entire sun shield is 
at least 5 cm above the horizontal plane of the sampler case or 
enclosure (disregarding the inlet and downtube) and external to the 
vertical plane of the nearest side or protuberance of the sampler case 
or enclosure. The maximum temperature measurement error of the ambient 
temperature measurement system shall be less than 1.6 [deg]C at 1 m/s 
wind speed and 1000 W/m2 solar radiation intensity.
    7.4.8.2 The ambient temperature sensor shall be of such a design and 
mounted in such a way as to facilitate its convenient dismounting and 
immersion in a liquid for calibration and comparison to the filter 
temperature sensor, under section 7.4.11 of this appendix.
    7.4.8.3 This ambient temperature measurement shall be updated at 
least every 30 seconds during both sampling and standby (non-sampling) 
modes of operation. A visual indication of the current (most recent) 
value of the ambient temperature measurement, updated at least every 30 
seconds, shall be available to the sampler operator during both sampling 
and standby (non-sampling) modes of operation, as specified in table L-1 
of section 7.4.19 of this appendix.
    7.4.8.4 This ambient temperature measurement shall be used for the 
purpose of monitoring filter temperature deviation from ambient 
temperature, as required by section 7.4.11 of this appendix, and may be 
used for purposes of effecting filter temperature control, under section 
7.4.10 of this appendix, or computation of volumetric flow rate, under 
sections 7.4.1 to 7.4.5 of this appendix, if appropriate.
    7.4.8.5 Following the end of each sample period, the sampler shall 
report the maximum, minimum, and average temperature for the sample 
period, as specified in table L-1 of section 7.4.19 of this appendix.
    7.4.9 Ambient barometric sensor. The sampler shall have capability 
to measure the barometric pressure of the air surrounding the sampler 
over a range of 600 to 800 mm Hg referenced as described in reference 3 
in section 13.0 of this appendix; also see part 53, subpart E of this 
chapter. This barometric pressure measurement shall have a resolution of 
5 mm Hg and an accuracy of 10 mm Hg and shall be 
updated at least every 30 seconds. A visual indication of the value of 
the current

[[Page 83]]

(most recent) barometric pressure measurement, updated at least every 30 
seconds, shall be available to the sampler operator during both sampling 
and standby (non-sampling) modes of operation, as specified in table L-1 
of section 7.4.19 of this appendix. This barometric pressure measurement 
may be used for purposes of computation of volumetric flow rate, under 
sections 7.4.1 to 7.4.5 of this appendix, if appropriate. Following the 
end of a sample period, the sampler shall report the maximum, minimum, 
and mean barometric pressures for the sample period, as specified in 
table L-1 of section 7.4.19 of this appendix.
    7.4.10 Filter temperature control (sampling and post-sampling). The 
sampler shall provide a means to limit the temperature rise of the 
sample filter (all sample filters for sequential samplers), from 
insolation and other sources, to no more 5 [deg]C above the temperature 
of the ambient air surrounding the sampler, during both sampling and 
post-sampling periods of operation. The post-sampling period is the non-
sampling period between the end of the active sampling period and the 
time of retrieval of the sample filter by the sampler operator.
    7.4.11 Filter temperature sensor(s).
    7.4.11.1 The sampler shall have the capability to monitor the 
temperature of the sample filter (all sample filters for sequential 
samplers) over the range of -30 to =45 [deg]C during both sampling and 
non-sampling periods. While the exact location of this temperature 
sensor is not explicitly specified, the filter temperature measurement 
system must demonstrate agreement, within 1 [deg]C, with a test 
temperature sensor located within 1 cm of the center of the filter 
downstream of the filter during both sampling and non-sampling modes, as 
specified in the filter temperature measurement test described in part 
53, subpart E of this chapter. This filter temperature measurement shall 
have a resolution of 0.1 [deg]C and accuracy of 1.0 [deg]C, referenced as described in reference 3 in 
section 13.0 of this appendix. This temperature sensor shall be of such 
a design and mounted in such a way as to facilitate its reasonably 
convenient dismounting and immersion in a liquid for calibration and 
comparison to the ambient temperature sensor under section 7.4.8 of this 
appendix.
    7.4.11.2 The filter temperature measurement shall be updated at 
least every 30 seconds during both sampling and standby (non-sampling) 
modes of operation. A visual indication of the current (most recent) 
value of the filter temperature measurement, updated at least every 30 
seconds, shall be available to the sampler operator during both sampling 
and standby (non-sampling) modes of operation, as specified in table L-1 
of section 7.4.19 of this appendix.
    7.4.11.3 For sequential samplers, the temperature of each filter 
shall be measured individually unless it can be shown, as specified in 
the filter temperature measurement test described in Sec. 53.57 of this 
chapter, that the temperature of each filter can be represented by fewer 
temperature sensors.
    7.4.11.4 The sampler shall also provide a warning flag indicator 
following any occurrence in which the filter temperature (any filter 
temperature for sequential samplers) exceeds the ambient temperature by 
more than 5 [deg]C for more than 30 consecutive minutes during either 
the sampling or post-sampling periods of operation, as specified in 
table L-1 of section 7.4.19 of this appendix, under section 10.12 of 
this appendix, regarding sample validity when a warning flag occurs. It 
is further recommended (not required) that the sampler be capable of 
recording the maximum differential between the measured filter 
temperature and the ambient temperature and its time and date of 
occurrence during both sampling and post-sampling (non-sampling) modes 
of operation and providing for those data to be accessible to the 
sampler operator following the end of the sample period, as suggested in 
table L-1 of section 7.4.19 of this appendix.
    7.4.12 Clock/timer system.
    (a) The sampler shall have a programmable real-time clock timing/
control system that:
    (1) Is capable of maintaining local time and date, including year, 
month, day-of-month, hour, minute, and second to an accuracy of 1.0 minute per month.
    (2) Provides a visual indication of the current system time, 
including year, month, day-of-month, hour, and minute, updated at least 
each minute, for operator verification.
    (3) Provides appropriate operator controls for setting the correct 
local time and date.
    (4) Is capable of starting the sample collection period and sample 
air flow at a specific, operator-settable time and date, and stopping 
the sample air flow and terminating the sampler collection period 24 
hours (1440 minutes) later, or at a specific, operator-settable time and 
date.
    (b) These start and stop times shall be readily settable by the 
sampler operator to within 1.0 minute. The system 
shall provide a visual indication of the current start and stop time 
settings, readable to 1.0 minute, for verification 
by the operator, and the start and stop times shall also be available 
via the data output port, as specified in table L-1 of section 7.4.19 of 
this appendix. Upon execution of a programmed sample period start, the 
sampler shall automatically reset all sample period information and 
warning flag indications pertaining to a previous sample period. Refer 
also to section 7.4.15.4 of this appendix regarding retention of current 
date and time and programmed start and stop times during a temporary 
electrical power interruption.
    7.4.13 Sample time determination. The sampler shall be capable of 
determining the

[[Page 84]]

elapsed sample collection time for each PM2.5 sample, 
accurate to within 1.0 minute, measured as the 
time between the start of the sampling period, under section 7.4.12 of 
this appendix and the termination of the sample period, under section 
7.4.12 of this appendix or section 7.4.4 of this appendix. This elapsed 
sample time shall not include periods when the sampler is inoperative 
due to a temporary interruption of electrical power, under section 
7.4.15.4 of this appendix. In the event that the elapsed sample time 
determined for the sample period is not within the range specified for 
the required sample period in section 3.3 of this appendix, the sampler 
shall set a warning flag indicator. The date and time of the start of 
the sample period, the value of the elapsed sample time for the sample 
period, and the flag indicator status shall be available to the sampler 
operator following the end of the sample period, as specified in table 
L-1 of section 7.4.19 of this appendix.
    7.4.14 Outdoor environmental enclosure. The sampler shall have an 
outdoor enclosure (or enclosures) suitable to protect the filter and 
other non-weatherproof components of the sampler from precipitation, 
wind, dust, extremes of temperature and humidity; to help maintain 
temperature control of the filter (or filters, for sequential samplers); 
and to provide reasonable security for sampler components and settings.
    7.4.15 Electrical power supply.
    7.4.15.1 The sampler shall be operable and function as specified 
herein when operated on an electrical power supply voltage of 105 to 125 
volts AC (RMS) at a frequency of 59 to 61 Hz. Optional operation as 
specified at additional power supply voltages and/or frequencies shall 
not be precluded by this requirement.
    7.4.15.2 The design and construction of the sampler shall comply 
with all applicable National Electrical Code and Underwriters 
Laboratories electrical safety requirements.
    7.4.15.3 The design of all electrical and electronic controls shall 
be such as to provide reasonable resistance to interference or 
malfunction from ordinary or typical levels of stray electromagnetic 
fields (EMF) as may be found at various monitoring sites and from 
typical levels of electrical transients or electronic noise as may often 
or occasionally be present on various electrical power lines.
    7.4.15.4 In the event of temporary loss of electrical supply power 
to the sampler, the sampler shall not be required to sample or provide 
other specified functions during such loss of power, except that the 
internal clock/timer system shall maintain its local time and date 
setting within 1 minute per week, and the sampler 
shall retain all other time and programmable settings and all data 
required to be available to the sampler operator following each sample 
period for at least 7 days without electrical supply power. When 
electrical power is absent at the operator-set time for starting a 
sample period or is interrupted during a sample period, the sampler 
shall automatically start or resume sampling when electrical power is 
restored, if such restoration of power occurs before the operator-set 
stop time for the sample period.
    7.4.15.5 The sampler shall have the capability to record and retain 
a record of the year, month, day-of-month, hour, and minute of the start 
of each power interruption of more than 1 minute duration, up to 10 such 
power interruptions per sample period. (More than 10 such power 
interruptions shall invalidate the sample, except where an exceedance is 
measured, under section 3.3 of this appendix.) The sampler shall provide 
for these power interruption data to be available to the sampler 
operator following the end of the sample period, as specified in table 
L-1 of section 7.4.19 of this appendix.
    7.4.16 Control devices and operator interface. The sampler shall 
have mechanical, electrical, or electronic controls, control devices, 
electrical or electronic circuits as necessary to provide the timing, 
flow rate measurement and control, temperature control, data storage and 
computation, operator interface, and other functions specified. 
Operator-accessible controls, data displays, and interface devices shall 
be designed to be simple, straightforward, reliable, and easy to learn, 
read, and operate under field conditions. The sampler shall have 
provision for operator input and storage of up to 64 characters of 
numeric (or alphanumeric) data for purposes of site, sampler, and sample 
identification. This information shall be available to the sampler 
operator for verification and change and for output via the data output 
port along with other data following the end of a sample period, as 
specified in table L-1 of section 7.4.19 of this appendix. All data 
required to be available to the operator following a sample collection 
period or obtained during standby mode in a post-sampling period shall 
be retained by the sampler until reset, either manually by the operator 
or automatically by the sampler upon initiation of a new sample 
collection period.
    7.4.17 Data output port requirement. The sampler shall have a 
standard RS-232C data output connection through which digital data may 
be exported to an external data storage or transmission device. All 
information which is required to be available at the end of each sample 
period shall be accessible through this data output connection. The 
information that shall be accessible though this output port is 
summarized in table L-1 of section 7.4.19 of this appendix. Since no 
specific format for the output data is provided, the sampler 
manufacturer or vendor shall make available to sampler purchasers 
appropriate computer software capable of receiving exported sampler data 
and correctly

[[Page 85]]

translating the data into a standard spreadsheet format and optionally 
any other formats as may be useful to sampler users. This requirement 
shall not preclude the sampler from offering other types of output 
connections in addition to the required RS-232C port.
    7.4.18 Operation/instruction manual. The sampler shall include an 
associated comprehensive operation or instruction manual, as required by 
part 53 of this chapter, which includes detailed operating instructions 
on the setup, operation, calibration, and maintenance of the sampler. 
This manual shall provide complete and detailed descriptions of the 
operational and calibration procedures prescribed for field use of the 
sampler and all instruments utilized as part of this reference method. 
The manual shall include adequate warning of potential safety hazards 
that may result from normal use or malfunction of the method and a 
description of necessary safety precautions. The manual shall also 
include a clear description of all procedures pertaining to 
installation, operation, periodic and corrective maintenance, and 
troubleshooting, and shall include parts identification diagrams.
    7.4.19 Data reporting requirements. The various information that the 
sampler is required to provide and how it is to be provided is 
summarized in the following table L-1.

                                Table L-1 to Appendix L of Part 50--Summary of Information To Be Provided by the Sampler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Availability                                        Format
                                    Appendix L section -------------------------------------------------------------------------------------------------
    Information to be provided          reference                        End of        Visual     Data  output    Digital  reading
                                                         Anytime \1\   period \2\    display \3\       \4\              \5\                 Units
--------------------------------------------------------------------------------------------------------------------------------------------------------
Flow rate, 30-second maximum       7.4.5.1............      [check]   ............      [check]             *   XX.X...............  L/min
 interval.
Flow rate, average for the sample  7.4.5.2............            *       [check]             *       [check]   XX.X...............  L/min
 period.
Flow rate, CV, for sample period.  7.4.5.2............            *       [check]             *       [check]   XX.X...............  %
Flow rate, 5-min. average out of   7.4.5.2............      [check]       [check]       [check]   [check][squf  On/Off
 spec. (FLAG \6\).                                                                                          ]
Sample volume, total.............  7.4.5.2............            *       [check]       [check]       [check]   XX.X...............  m\3\
Temperature, ambient, 30-second    7.4.8..............      [check]   ............      [check]   ............  XX.X...............   [deg]C
 interval.
Temperature, ambient, min., max.,  7.4.8..............            *       [check]       [check]   [check][squf  XX.X...............   [deg]C
 average for the sample period.                                                                             ]
Baro. pressure, ambient, 30-       7.4.9..............      [check]   ............      [check]   ............  XXX................  mm Hg
 second interval.
Baro. pressure, ambient, min.,     7.4.9..............            *       [check]       [check]   [check][squf  XXX................  mm Hg
 max., average for the sample                                                                               ]
 period.
Filter temperature, 30-second      7.4.11.............      [check]   ............      [check]   ............  XX.X...............   [deg]C
 interval.
Filter temp. differential, 30-     7.4.11.............            *       [check]       [check]   [check][squf  On/Off
 second interval, out of spec.                                                                              ]
 (FLAG \6\).
Filter temp., maximum              7.4.11.............            *             *             *             *   X.X, YY/MM/DD HH.mm   [deg]C, Yr/Mon/Day
 differential from ambient, date,                                                                                                     Hrs. min
 time of occurrence.
Date and Time....................  7.4.12.............      [check]   ............      [check]   ............  YY/MM/DD HH.mm.....  Yr/Mon/Day Hrs. min
Sample start and stop time         7.4.12.............      [check]       [check]       [check]       [check]   YY/MM/DD HH.mm.....  Yr/Mon/Day Hrs. min
 settings.

[[Page 86]]

 
Sample period start time.........  7.4.12.............  ............      [check]       [check]       [check]   YY/MM/DD HH.mm.....  Yr/Mon/Day Hrs. min
Elapsed sample time..............  7.4.13.............            *       [check]       [check]       [check]   HH.mm..............  Hrs. min
Elapsed sample time, out of spec.  7.4.13.............  ............      [check]       [check]   [check][squf  On/Off
 (FLAG \6\).                                                                                                ]
Power interruptions <=1 min.,      7.4.15.5...........            *       [check]             *       [check]   1HH.mm, 2HH.mm,      Hrs. min
 start time of first 10.                                                                                         etc..
User-entered information, such as  7.4.16.............      [check]       [check]       [check]   [check][squf  As entered ........
 sampler and site identification.                                                                           ]
--------------------------------------------------------------------------------------------------------------------------------------------------------
[check] Provision of this information is required.
* Provision of this information is optional. If information related to the entire sample period is optionally provided prior to the end of the sample
  period, the value provided should be the value calculated for the portion of the sampler period completed up to the time the information is provided.
[squf] Indicates that this information is also required to be provided to the Air Quality System (AQS) data bank; see Sec. 58.16 of this chapter. For
  ambient temperature and barometric pressure, only the average for the sample period must be reported.
1. Information is required to be available to the operator at any time the sampler is operating, whether sampling or not.
2. Information relates to the entire sampler period and must be provided following the end of the sample period until reset manually by the operator or
  automatically by the sampler upon the start of a new sample period.
3. Information shall be available to the operator visually.
4. Information is to be available as digital data at the sampler's data output port specified in section 7.4.16 of this appendix following the end of
  the sample period until reset manually by the operator or automatically by the sampler upon the start of a new sample period.
5. Digital readings, both visual and data output, shall have not less than the number of significant digits and resolution specified.
6. Flag warnings may be displayed to the operator by a single flag indicator or each flag may be displayed individually. Only a set (on) flag warning
  must be indicated; an off (unset) flag may be indicated by the absence of a flag warning. Sampler users should refer to section 10.12 of this appendix
  regarding the validity of samples for which the sampler provided an associated flag warning.

    8.0 Filter Weighing. See reference 2 in section 13.0 of this 
appendix, for additional, more detailed guidance.
    8.1 Analytical balance. The analytical balance used to weigh filters 
must be suitable for weighing the type and size of filters specified, 
under section 6.0 of this appendix, and have a readability of 1 [micro]g. The balance shall be calibrated as specified 
by the manufacturer at installation and recalibrated immediately prior 
to each weighing session. See reference 2 in section 13.0 of this 
appendix for additional guidance.
    8.2 Filter conditioning. All sample filters used shall be 
conditioned immediately before both the pre- and post-sampling weighings 
as specified below. See reference 2 in section 13.0 of this appendix for 
additional guidance.
    8.2.1 Mean temperature. 20 - 23 [deg]C.
    8.2.2 Temperature control. 2 [deg]C over 24 
hours.
    8.2.3 Mean humidity. Generally, 30-40 percent relative humidity; 
however, where it can be shown that the mean ambient relative humidity 
during sampling is less than 30 percent, conditioning is permissible at 
a mean relative humidity within 5 relative 
humidity percent of the mean ambient relative humidity during sampling, 
but not less than 20 percent.
    8.2.4 Humidity control. 5 relative humidity 
percent over 24 hours.
    8.2.5 Conditioning time. Not less than 24 hours.
    8.3 Weighing procedure.
    8.3.1 New filters should be placed in the conditioning environment 
immediately upon arrival and stored there until the pre-sampling 
weighing. See reference 2 in section 13.0 of this appendix for 
additional guidance.
    8.3.2 The analytical balance shall be located in the same controlled 
environment in which the filters are conditioned. The filters shall be 
weighed immediately following the conditioning period without 
intermediate or transient exposure to other conditions or environments.
    8.3.3 Filters must be conditioned at the same conditions (humidity 
within 5 relative humidity percent) before both 
the pre- and post-sampling weighings.
    8.3.4 Both the pre- and post-sampling weighings should be carried 
out on the same

[[Page 87]]

analytical balance, using an effective technique to neutralize static 
charges on the filter, under reference 2 in section 13.0 of this 
appendix. If possible, both weighings should be carried out by the same 
analyst.
    8.3.5 The pre-sampling (tare) weighing shall be within 30 days of 
the sampling period.
    8.3.6 The post-sampling conditioning and weighing shall be completed 
within 240 hours (10 days) after the end of the sample period, unless 
the filter sample is maintained at temperatures below the average 
ambient temperature during sampling (or 4 [deg]C or below for average 
sampling temperatures less than 4 [deg]C) during the time between 
retrieval from the sampler and the start of the conditioning, in which 
case the period shall not exceed 30 days. Reference 2 in section 13.0 of 
this appendix has additional guidance on transport of cooled filters.
    8.3.7 Filter blanks.
    8.3.7.1 New field blank filters shall be weighed along with the pre-
sampling (tare) weighing of each lot of PM2.5 filters. These 
blank filters shall be transported to the sampling site, installed in 
the sampler, retrieved from the sampler without sampling, and reweighed 
as a quality control check.
    8.3.7.2 New laboratory blank filters shall be weighed along with the 
pre-sampling (tare) weighing of each set of PM2.5 filters. 
These laboratory blank filters should remain in the laboratory in 
protective containers during the field sampling and should be reweighed 
as a quality control check.
    8.3.8 Additional guidance for proper filter weighing and related 
quality assurance activities is provided in reference 2 in section 13.0 
of this appendix.
    9.0 Calibration. Reference 2 in section 13.0 of this appendix 
contains additional guidance.
    9.1 General requirements.
    9.1.1 Multipoint calibration and single-point verification of the 
sampler's flow rate measurement device must be performed periodically to 
establish and maintain traceability of subsequent flow measurements to a 
flow rate standard.
    9.1.2 An authoritative flow rate standard shall be used for 
calibrating or verifying the sampler's flow rate measurement device with 
an accuracy of 2 percent. The flow rate standard 
shall be a separate, stand-alone device designed to connect to the flow 
rate measurement adapter, Figure L-30 of this appendix. This flow rate 
standard must have its own certification and be traceable to a National 
Institute of Standards and Technology (NIST) primary standard for volume 
or flow rate. If adjustments to the sampler's flow rate measurement 
system calibration are to be made in conjunction with an audit of the 
sampler's flow measurement system, such adjustments shall be made 
following the audit. Reference 2 in section 13.0 of this appendix 
contains additional guidance.
    9.1.3 The sampler's flow rate measurement device shall be re-
calibrated after electromechanical maintenance or transport of the 
sampler.
    9.2 Flow rate calibration/verification procedure.
    9.2.1 PM2.5 samplers may employ various types of flow 
control and flow measurement devices. The specific procedure used for 
calibration or verification of the flow rate measurement device will 
vary depending on the type of flow rate controller and flow rate 
measurement employed. Calibration shall be in terms of actual ambient 
volumetric flow rates (Qa), measured at the sampler's inlet 
downtube. The generic procedure given here serves to illustrate the 
general steps involved in the calibration of a PM2.5 sampler. 
The sampler operation/instruction manual required under section 7.4.18 
of this appendix and the Quality Assurance Handbook in reference 2 in 
section 13.0 of this appendix provide more specific and detailed 
guidance for calibration.
    9.2.2 The flow rate standard used for flow rate calibration shall 
have its own certification and be traceable to a NIST primary standard 
for volume or flow rate. A calibration relationship for the flow rate 
standard, e.g., an equation, curve, or family of curves relating actual 
flow rate (Qa) to the flow rate indicator reading, shall be 
established that is accurate to within 2 percent over the expected range 
of ambient temperatures and pressures at which the flow rate standard 
may be used. The flow rate standard must be re-calibrated or re-verified 
at least annually.
    9.2.3 The sampler flow rate measurement device shall be calibrated 
or verified by removing the sampler inlet and connecting the flow rate 
standard to the sampler's downtube in accordance with the operation/
instruction manual, such that the flow rate standard accurately measures 
the sampler's flow rate. The sampler operator shall first carry out a 
sampler leak check and confirm that the sampler passes the leak test and 
then verify that no leaks exist between the flow rate standard and the 
sampler.
    9.2.4 The calibration relationship between the flow rate (in actual 
L/min) indicated by the flow rate standard and by the sampler's flow 
rate measurement device shall be established or verified in accordance 
with the sampler operation/instruction manual. Temperature and pressure 
corrections to the flow rate indicated by the flow rate standard may be 
required for certain types of flow rate standards. Calibration of the 
sampler's flow rate measurement device shall consist of at least three 
separate flow rate measurements (multipoint calibration) evenly spaced 
within the range of -10 percent to =10 percent of the sampler's 
operational flow rate, section 7.4.1 of this appendix. Verification of 
the sampler's flow rate shall consist of one flow

[[Page 88]]

rate measurement at the sampler's operational flow rate. The sampler 
operation/instruction manual and reference 2 in section 13.0 of this 
appendix provide additional guidance.
    9.2.5 If during a flow rate verification the reading of the 
sampler's flow rate indicator or measurement device differs by 4 percent or more from the flow rate measured by the 
flow rate standard, a new multipoint calibration shall be performed and 
the flow rate verification must then be repeated.
    9.2.6 Following the calibration or verification, the flow rate 
standard shall be removed from the sampler and the sampler inlet shall 
be reinstalled. Then the sampler's normal operating flow rate (in L/min) 
shall be determined with a clean filter in place. If the flow rate 
indicated by the sampler differs by 2 percent or 
more from the required sampler flow rate, the sampler flow rate must be 
adjusted to the required flow rate, under section 7.4.1 of this 
appendix.
    9.3 Periodic calibration or verification of the calibration of the 
sampler's ambient temperature, filter temperature, and barometric 
pressure measurement systems is also required. Reference 3 of section 
13.0 of this appendix contains additional guidance.
    10.0 PM2.5 Measurement Procedure. The detailed procedure 
for obtaining valid PM2.5 measurements with each specific 
sampler designated as part of a reference method for PM2.5 
under part 53 of this chapter shall be provided in the sampler-specific 
operation or instruction manual required by section 7.4.18 of this 
appendix. Supplemental guidance is provided in section 2.12 of the 
Quality Assurance Handbook listed in reference 2 in section 13.0 of this 
appendix. The generic procedure given here serves to illustrate the 
general steps involved in the PM2.5 sample collection and 
measurement, using a PM2.5 reference method sampler.
    10.1 The sampler shall be set up, calibrated, and operated in 
accordance with the specific, detailed guidance provided in the specific 
sampler's operation or instruction manual and in accordance with a 
specific quality assurance program developed and established by the 
user, based on applicable supplementary guidance provided in reference 2 
in section 13.0 of this appendix.
    10.2 Each new sample filter shall be inspected for correct type and 
size and for pinholes, particles, and other imperfections. Unacceptable 
filters should be discarded. A unique identification number shall be 
assigned to each filter, and an information record shall be established 
for each filter. If the filter identification number is not or cannot be 
marked directly on the filter, alternative means, such as a number-
identified storage container, must be established to maintain positive 
filter identification.
    10.3 Each filter shall be conditioned in the conditioning 
environment in accordance with the requirements specified in section 8.2 
of this appendix.
    10.4 Following conditioning, each filter shall be weighed in 
accordance with the requirements specified in section 8.0 of this 
appendix and the presampling weight recorded with the filter 
identification number.
    10.5 A numbered and preweighed filter shall be installed in the 
sampler following the instructions provided in the sampler operation or 
instruction manual.
    10.6 The sampler shall be checked and prepared for sample collection 
in accordance with instructions provided in the sampler operation or 
instruction manual and with the specific quality assurance program 
established for the sampler by the user.
    10.7 The sampler's timer shall be set to start the sample collection 
at the beginning of the desired sample period and stop the sample 
collection 24 hours later.
    10.8 Information related to the sample collection (site location or 
identification number, sample date, filter identification number, and 
sampler model and serial number) shall be recorded and, if appropriate, 
entered into the sampler.
    10.9 The sampler shall be allowed to collect the PM2.5 
sample during the set 24-hour time period.
    10.10 Within 177 hours (7 days, 9 hours) of the end of the sample 
collection period, the filter, while still contained in the filter 
cassette, shall be carefully removed from the sampler, following the 
procedure provided in the sampler operation or instruction manual and 
the quality assurance program, and placed in a protective container. The 
protective container shall contain no loose material that could be 
transferred to the filter. The protective container shall hold the 
filter cassette securely such that the cover shall not come in contact 
with the filter's surfaces. Reference 2 in section 13.0 of this appendix 
contains additional information.
    10.11 The total sample volume in actual m\3\ for the sampling period 
and the elapsed sample time shall be obtained from the sampler and 
recorded in accordance with the instructions provided in the sampler 
operation or instruction manual. All sampler warning flag indications 
and other information required by the local quality assurance program 
shall also be recorded.
    10.12 All factors related to the validity or representativeness of 
the sample, such as sampler tampering or malfunctions, unusual 
meteorological conditions, construction activity, fires or dust storms, 
etc. shall be recorded as required by the local quality assurance 
program. The occurrence of a flag warning during a sample period shall 
not necessarily indicate an invalid sample but rather shall indicate the 
need for specific review of the QC data by a quality assurance officer 
to determine sample validity.

[[Page 89]]

    10.13 After retrieval from the sampler, the exposed filter 
containing the PM2.5 sample should be transported to the 
filter conditioning environment as soon as possible, ideally to arrive 
at the conditioning environment within 24 hours for conditioning and 
subsequent weighing. During the period between filter retrieval from the 
sampler and the start of the conditioning, the filter shall be 
maintained as cool as practical and continuously protected from exposure 
to temperatures over 25 [deg]C to protect the integrity of the sample 
and minimize loss of volatile components during transport and storage. 
See section 8.3.6 of this appendix regarding time limits for completing 
the post-sampling weighing. See reference 2 in section 13.0 of this 
appendix for additional guidance on transporting filter samplers to the 
conditioning and weighing laboratory.
    10.14. The exposed filter containing the PM2.5 sample 
shall be re-conditioned in the conditioning environment in accordance 
with the requirements specified in section 8.2 of this appendix.
    10.15. The filter shall be reweighed immediately after conditioning 
in accordance with the requirements specified in section 8.0 of this 
appendix, and the postsampling weight shall be recorded with the filter 
identification number.
    10.16 The PM2.5 concentration shall be calculated as 
specified in section 12.0 of this appendix.
    11.0 Sampler Maintenance. The sampler shall be maintained as 
described by the sampler's manufacturer in the sampler-specific 
operation or instruction manual required under section 7.4.18 of this 
appendix and in accordance with the specific quality assurance program 
developed and established by the user based on applicable supplementary 
guidance provided in reference 2 in section 13.0 of this appendix.
    12.0 Calculations
    12.1 (a) The PM2.5 concentration is calculated as:

PM2.5 = (Wf - Wi)/Va

where:

PM2.5 = mass concentration of PM2.5, [micro]g/
m\3\;
Wf, Wi = final and initial weights, respectively, 
of the filter used to collect the PM2.5 particle sample, 
[micro]g;
Va = total air volume sampled in actual volume units, as 
provided by the sampler, m\3\.

    Note: Total sample time must be between 1,380 and 1,500 minutes (23 
and 25 hrs) for a fully valid PM2.5 sample; however, see also 
section 3.3 of this appendix.

    13.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA/600/R-94/038a, April 1994. Available from 
CERI, ORD Publications, U.S. Environmental Protection Agency, 26 West 
Martin Luther King Drive, Cincinnati, Ohio 45268.
    2. Quality Assurance Guidance Document 2.12. Monitoring 
PM2.5 in Ambient Air Using Designated Reference or Class I 
Equivalent Methods. U.S. EPA, National Exposure Research Laboratory. 
Research Triangle Park, NC, November 1988 or later edition. Currently 
available at: http://www.epa.gov/ttn/amtic/pmqainf.html.
    3. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume IV: Meteorological Measurements, (Revised Edition) EPA/600/R-94/
038d, March, 1995. Available from CERI, ORD Publications, U.S. 
Environmental Protection Agency, 26 West Martin Luther King Drive, 
Cincinnati, Ohio 45268.
    4. Military standard specification (mil. spec.) 8625F, Type II, 
Class 1 as listed in Department of Defense Index of Specifications and 
Standards (DODISS), available from DODSSP-Customer Service, 
Standardization Documents Order Desk, 700 Robbins Avenue, Building 4D, 
Philadelphia, PA 1911-5094.
    14.0 Figures L-1 through L-30 to Appendix L.

[[Page 90]]

[GRAPHIC] [TIFF OMITTED] TR18JY97.022


[[Page 91]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.023


[[Page 92]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.024


[[Page 93]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.025


[[Page 94]]


[GRAPHIC] [TIFF OMITTED] TR17FE98.004


[[Page 95]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.027


[[Page 96]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.028


[[Page 97]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.029


[[Page 98]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.030


[[Page 99]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.031


[[Page 100]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.032


[[Page 101]]


[GRAPHIC] [TIFF OMITTED] TR17FE98.005


[[Page 102]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.034


[[Page 103]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.035


[[Page 104]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.036


[[Page 105]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.037


[[Page 106]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.038


[[Page 107]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.039


[[Page 108]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.040


[[Page 109]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.041


[[Page 110]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.042


[[Page 111]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.043


[[Page 112]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.044


[[Page 113]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.045


[[Page 114]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.046


[[Page 115]]


[GRAPHIC] [TIFF OMITTED] TR17FE98.006


[[Page 116]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.048


[[Page 117]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.049


[[Page 118]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.050


[[Page 119]]


[GRAPHIC] [TIFF OMITTED] TR18JY97.051


[62 FR 38714, July 18, 1997, as amended at 64 FR 19719, Apr. 22, 1999; 
71 FR 61226, Oct. 17, 2006]

[[Page 120]]



                  Sec. Appendix M to Part 50 [Reserved]



 Sec. Appendix N to Part 50--Interpretation of the National Ambient Air 
                 Quality Standards for PM2.5

                               1. General

    (a) This appendix explains the data handling conventions and 
computations necessary for determining when the annual and 24-hour 
primary and secondary national ambient air quality standards (NAAQS) for 
PM2.5 specified in Sec. 50.7 and Sec. 50.13 of this part 
are met. PM2.5, defined as particles with an aerodynamic 
diameter less than or equal to a nominal 2.5 micrometers, is measured in 
the ambient air by a Federal reference method (FRM) based on appendix L 
of this part, as applicable, and designated in accordance with part 53 
of this chapter, or by a Federal equivalent method (FEM) designated in 
accordance with part 53 of this chapter, or by an Approved Regional 
Method (ARM) designated in accordance with part 58 of this chapter. Data 
handling and computation procedures to be used in making comparisons 
between reported PM2.5 concentrations and the levels of the 
PM2.5 NAAQS are specified in the following sections.
    (b) Data resulting from exceptional events, for example structural 
fires or high winds, may be given special consideration. In some cases, 
it may be appropriate to exclude these data in whole or part because 
they could result in inappropriate values to compare with the levels of 
the PM2.5 NAAQS. In other cases, it may be more appropriate 
to retain the data for comparison with the levels of the 
PM2.5 NAAQS and then for EPA to formulate the appropriate 
regulatory response.
    (c) The terms used in this appendix are defined as follows:
    Annual mean refers to a weighted arithmetic mean, based on quarterly 
means, as defined in section 4.4 of this appendix.
    Creditable samples are samples that are given credit for data 
completeness. They include valid samples collected on required sampling 
days and valid ``make-up'' samples taken for missed or invalidated 
samples on required sampling days.
    Daily values for PM2.5 refers to the 24-hour average 
concentrations of PM2.5 calculated (averaged from hourly 
measurements) or measured from midnight to midnight (local standard 
time) that are used in NAAQS computations.
    Designated monitors are those monitoring sites designated in a State 
or local agency PM Monitoring Network Description in accordance with 
part 58 of this chapter.
    Design values are the metrics (i.e., statistics) that are compared 
to the NAAQS levels to determine compliance, calculated as shown in 
section 4 of this appendix:
    (1) The 3-year average of annual means for a single monitoring site 
or a group of monitoring sites (referred to as the ``annual standard 
design value''). If spatial averaging has been approved by EPA for a 
group of sites which meet the criteria specified in section 2(b) of this 
appendix and section 4.7.5 of appendix D of 40 CFR part 58, then 3 years 
of spatially averaged annual means will be averaged to derive the annual 
standard design value for that group of sites (further referred to as 
the ``spatially averaged annual standard design value''). Otherwise, the 
annual standard design value will represent the 3-year average of annual 
means for a single site (further referred to as the ``single site annual 
standard design value'').
    (2) The 3-year average of annual 98th percentile 24-hour average 
values recorded at each monitoring site (referred to as the ``24-hour 
standard design value'').
    Extra samples are non-creditable samples. They are daily values that 
do not occur on scheduled sampling days and that can not be used as 
make-ups for missed or invalidated scheduled samples. Extra samples are 
used in mean calculations and are subject to selection as a 98th 
percentile.
    Make-up samples are samples taken to supplant missed or invalidated 
required scheduled samples. Make-ups can be made by either the primary 
or the collocated instruments. Make-up samples are either taken before 
the next required sampling day or exactly one week after the missed (or 
voided) sampling day. Also, to be considered a valid make-up, the 
sampling must be administered according to EPA guidance.
    98th percentile is the daily value out of a year of PM2.5 
monitoring data below which 98 percent of all daily values fall.
    Year refers to a calendar year.

                     2.0 Monitoring Considerations.

    (a) Section 58.30 of this chapter specifies which monitoring 
locations are eligible for making comparisons with the PM2.5 
standards.
    (b) To qualify for spatial averaging, monitoring sites must meet the 
criterion specified in section 4.7.5 of appendix D of 40 CFR part 58 as 
well as the following requirements:
    (1) The annual mean concentration at each site shall be within 10 
percent of the spatially averaged annual mean.
    (2) The daily values for each site pair among the 3-year period 
shall yield a correlation coefficient of at least 0.9 for each calendar 
quarter.
    (3) All of the monitoring sites should principally be affected by 
the same major emission sources of PM2.5. For example, this 
could be demonstrated by site-specific chemical speciation profiles 
confirming all major component concentration averages to be within 10 
percent for each calendar quarter.

[[Page 121]]

    (4) The requirements in paragraphs (b)(1) through (3) of this 
section shall be met for 3 consecutive years in order to produce a valid 
spatially averaged annual standard design value. Otherwise, the 
individual (single) site annual standard design values shall be compared 
directly to the level of the annual NAAQS.
    (c) Section 58.12 of this chapter specifies the required minimum 
frequency of sampling for PM2.5. Exceptions to the specified 
sampling frequencies, such as a reduced frequency during a season of 
expected low concentrations (i.e., ``seasonal sampling''), are subject 
to the approval of EPA. Annual 98th percentile values are to be 
calculated according to equation 5 in section 4.5 of this appendix when 
a site operates on a ``seasonal sampling'' schedule.

3.0 Requirements for Data Used for Comparisons With the PM2.5 
                NAAQS and Data Reporting Considerations.

    (a) Except as otherwise provided in this appendix, only valid FRM/
FEM/ARM PM2.5 data required to be submitted to EPA's Air 
Quality System (AQS) shall be used in the design value calculations.
    (b) PM2.5 measurement data (typically hourly for 
continuous instruments and daily for filter-based instruments) shall be 
reported to AQS in micrograms per cubic meter ([micro]g/m\3\) to one 
decimal place, with additional digits to the right being truncated.
    (c) Block 24-hour averages shall be computed from available hourly 
PM2.5 concentration data for each corresponding day of the 
year and the result shall be stored in the first, or start, hour (i.e., 
midnight, hour `0') of the 24-hour period. A 24-hour average shall be 
considered valid if at least 75 percent (i.e., 18) of the hourly 
averages for the 24-hour period are available. In the event that less 
than all 24 hourly averages are available (i.e., less than 24, but at 
least 18), the 24-hour average shall be computed on the basis of the 
hours available using the number of available hours as the divisor 
(e.g., 19). 24-hour periods with seven or more missing hours shall be 
considered valid if, after substituting zero for all missing hourly 
concentrations, the 24-hour average concentration is greater than the 
level of the standard. The computed 24-hour average PM2.5 
concentrations shall be reported to one decimal place (the additional 
digits to the right of the first decimal place are truncated, consistent 
with the data handling procedures for the reported data).
    (d) Except for calculation of spatially averaged annual means and 
spatially averaged annual standard design values, all other calculations 
shown in this appendix shall be implemented on a site-level basis. Site 
level data shall be processed as follows:
    (1) The default dataset for a site shall consist of the measured 
concentrations recorded from the designated primary FRM/FEM/ARM monitor. 
The primary monitor shall be designated in the appropriate State or 
local agency PM Monitoring Network Description. All daily values 
produced by the primary sampler are considered part of the site record 
(i.e., that site's daily value); this includes all creditable samples 
and all extra samples.
    (2) Data for the primary monitor shall be augmented as much as 
possible with data from collocated FRM/FEM/ARM monitors. If a valid 24-
hour measurement is not produced from the primary monitor for a 
particular day (scheduled or otherwise), but a valid sample is generated 
by a collocated FRM/FEM/ARM instrument (and recorded in AQS), then that 
collocated value shall be considered part of the site data record (i.e., 
that site's daily value). If more than one valid collocated FRM/FEM/ARM 
value is available, the average of those valid collocated values shall 
be used as the daily value.
    (e) All daily values in the composite site record are used in annual 
mean and 98th percentile calculations, however, not all daily values are 
give credit towards data completeness requirements. Only ``creditable'' 
samples are given credit for data completeness. Creditable samples 
include valid samples on scheduled sampling days and valid make-up 
samples. All other types of daily values are referred to as ``extra'' 
samples.

                  4.0 Comparisons With the PM2.5 NAAQS.

                   4.1 Annual PM2.5 NAAQS.

    (a) The annual PM2.5 NAAQS is met when the annual 
standard design value is less than or equal to 15.0 micrograms per cubic 
meter ([micro]g/m\3\).
    (b) For single site comparisons, 3 years of valid annual means are 
required to produce a valid annual standard design value. In the case of 
spatial averaging, 3 years of valid spatially averaged annual means are 
required to produce a valid annual standard design value. Designated 
sites with less than 3 years of data shall be included in annual spatial 
averages for those years that data completeness requirements are met. A 
year meets data completeness requirements when at least 75 percent of 
the scheduled sampling days for each quarter have valid data. [Quarterly 
data capture rates (expressed as a percentage) are specifically 
calculated as the number of creditable samples for the quarter divided 
by the number of scheduled samples for the quarter, the result then 
multiplied by 100 and rounded to the nearest integer.] However, years 
with at least 11 samples in each quarter shall be considered valid, 
notwithstanding quarters with less than complete data, if the resulting 
annual mean, spatially

[[Page 122]]

averaged annual mean concentration, or resulting annual standard design 
value concentration (rounded according to the conventions of section 4.3 
of this appendix) is greater than the level of the standard. 
Furthermore, where the explicit 11 sample per quarter requirement is not 
met, the site annual mean shall still be considered valid if, by 
substituting a low value (described below) for the missing data in the 
deficient quarters (substituting enough to meet the 11 sample minimum), 
the computation still yields a recalculated annual mean, spatially 
averaged annual mean concentration, or annual standard design value 
concentration over the level of the standard. The low value used for 
this substitution test shall be the lowest reported daily value in the 
site data record for that calendar quarter over the most recent 3-year 
period. If an annual mean is deemed complete using this test, the 
original annual mean (without substituted low values) shall be 
considered the official mean value for this site, not the result of the 
recalculated test using the low values.
    (c) The use of less than complete data is subject to the approval of 
EPA, which may consider factors such as monitoring site closures/moves, 
monitoring diligence, and nearby concentrations in determining whether 
to use such data.
    (d) The equations for calculating the annual standard design values 
are given in section 4.4 of this appendix.

                        4.2 24-Hour PM2.5 NAAQS.

    (a) The 24-hour PM2.5 NAAQS is met when the 24-hour 
standard design value at each monitoring site is less than or equal to 
35 [micro]g/m\3\. This comparison shall be based on 3 consecutive, 
complete years of air quality data. A year meets data completeness 
requirements when at least 75 percent of the scheduled sampling days for 
each quarter have valid data. However, years shall be considered valid, 
notwithstanding quarters with less than complete data (even quarters 
with less than 11 samples), if the resulting annual 98th percentile 
value or resulting 24-hour standard design value (rounded according to 
the conventions of section 4.3 of this appendix) is greater than the 
level of the standard.
    (b) The use of less than complete data is subject to the approval of 
EPA which may consider factors such as monitoring site closures/moves, 
monitoring diligence, and nearby concentrations in determining whether 
to use such data for comparisons to the NAAQS.
    (c) The procedures and equations for calculating the 24-hour 
standard design values are given in section 4.5 of this appendix.
    4.3 Rounding Conventions. For the purposes of comparing calculated 
values to the applicable level of the standard, it is necessary to round 
the final results of the calculations described in sections 4.4 and 4.5 
of this appendix. Results for all intermediate calculations shall not be 
rounded.
    (a) Annual PM2.5 standard design values shall be rounded 
to the nearest 0.1 [micro]g/m\3\ (decimals 0.05 and greater are rounded 
up to the next 0.1, and any decimal lower than 0.05 is rounded down to 
the nearest 0.1).
    (b) 24-hour PM2.5 standard design values shall be rounded 
to the nearest 1 [micro]g/m\3\ (decimals 0.5 and greater are rounded up 
to the nearest whole number, and any decimal lower than 0.5 is rounded 
down to the nearest whole number).

                4.4 Equations for the Annual PM2.5 NAAQS.

    (a) An annual mean value for PM2.5 is determined by first 
averaging the daily values of a calendar quarter using equation 1 of 
this appendix:
[GRAPHIC] [TIFF OMITTED] TR17OC06.003

Where:

Xq,y,s = the mean for quarter q of the year y for site s;
nq = the number of daily values in the quarter; and
xi q,y,s = the ith value in quarter q for year y 
for site s.

    (b) Equation 2 of this appendix is then used to calculate the site 
annual mean:
[GRAPHIC] [TIFF OMITTED] TR17OC06.004

Where:

Xy,s = the annual mean concentration for year y (y = 1, 2, or 
3) and for site s; and
Xq,y,s = the mean for quarter q of year y for site s.

    (c) If spatial averaging is utilized, the site-based annual means 
will then be averaged together to derive the spatially averaged annual 
mean using equation 3 of this appendix. Otherwise (i.e., for single site 
comparisons), skip to equation 4.B of this appendix.
[GRAPHIC] [TIFF OMITTED] TR17OC06.005

Where:

xy = the spatially averaged mean for year y,
xy,s = the annual mean for year y and site s for sites 
designated to be averaged that meet completeness criteria , and

[[Page 123]]

ns = the number of sites designated to be averaged that meet 
completeness criteria.

    (d) The annual standard design value is calculated using equation 4A 
of this appendix when spatial averaging and equation 4B of this appendix 
when not spatial averaging:
[GRAPHIC] [TIFF OMITTED] TR17OC06.006

[GRAPHIC] [TIFF OMITTED] TR17OC06.007

Where:

x = the annual standard design value (the spatially averaged annual 
standard design value for equation 4A of this appendix and the single 
site annual standard design value for equation 4B of this appendix); and
xy = the spatially averaged annual mean for year y (result of 
equation 3 of this appendix) when spatial averaging is used, or
xy,s the annual mean for year y and site s (result of 
equation 2 of this appendix) when spatial averaging is not used.

    (e) The annual standard design value is rounded according to the 
conventions in section 4.3 of this appendix before a comparison with the 
standard is made.

   4.5 Procedures and Equations for the 24-Hour PM2.5 NAAQS

    (a) When the data for a particular site and year meet the data 
completeness requirements in section 4.2 of this appendix, calculation 
of the 98th percentile is accomplished by the steps provided in this 
subsection. Table 1 of this appendix shall be used to identify annual 
98th percentile values, except that where a site operates on an approved 
seasonal sampling schedule, equation 5 of this appendix shall be used 
instead.
    (1) Regular procedure for identifying annual 98th percentile values. 
Identification of annual 98th percentile values using the regular 
procedure (table 1) will be based on the creditable number of samples 
(as described below), rather than on the actual number of samples. 
Credit will not be granted for extra (non-creditable) samples. Extra 
samples, however, are candidates for selection as the annual 98th 
percentile. [The creditable number of samples will determine how deep to 
go into the data distribution, but all samples (creditable and extra) 
will be considered when making the percentile assignment.] The annual 
creditable number of samples is the sum of the four quarterly creditable 
number of samples.
    Procedure: Sort all the daily values from a particular site and year 
by descending value. (For example: (x[1], x[2], x[3], * * *, x[n]). In 
this case, x[1] is the largest number and x[n] is the smallest value.) 
The 98th percentile is determined from this sorted series of daily 
values which is ordered from the highest to the lowest number. Using the 
left column of table 1, determine the appropriate range (i.e., row) for 
the annual creditable number of samples for year y (cny). The 
corresponding ``n'' value in the right column identifies the rank of the 
annual 98th percentile value in the descending sorted list of daily site 
values for year y. Thus, P0.98, y = the nth largest value.

                                 Table 1
------------------------------------------------------------------------
                                             P0.98, y is the nth maximum
  Annual creditable number of samples for    value of the year, where n
             year ``y'' (cny)                   is the listed number
------------------------------------------------------------------------
1-50......................................  1
51-100....................................  2
101-150...................................  3
151-200...................................  4
201-250...................................  5
251-300...................................  6
301-350...................................  7
351-366...................................  8
------------------------------------------------------------------------

    (2) Formula for computing annual 98th percentile values when 
sampling frequencies are seasonal.
    Procedure: Calculate the annual 98th percentiles by determining the 
smallest measured concentration, x, that makes W(x) greater than 0.98 
using equation 5 of this appendix:
[GRAPHIC] [TIFF OMITTED] TR51AD07.000


[[Page 124]]


Where:

dHigh = number of calendar days in the ``High'' season;
dLow = number of calendar days in the ``Low'' season;
dHigh + dLow = days in a year; and
[GRAPHIC] [TIFF OMITTED] TR51AD07.001

Such that ``a'' can be either ``High'' or ``Low''; ``x'' is the measured 
concentration; and ``dHigh/(dHigh + 
dLow) and dLow /(dHigh + 
dLow)'' are constant and are called seasonal ``weights.''
    (b) The 24-hour standard design value is then calculated by 
averaging the annual 98th percentiles using equation 6 of this appendix:
[GRAPHIC] [TIFF OMITTED] TR51AD07.002

    (c) The 24-hour standard design value (3-year average 98th 
percentile) is rounded according to the conventions in section 4.3 of 
this appendix before a comparison with the standard is made.

[71 FR 61227, Oct. 17, 2006, as amended at 73 FR 1502, Jan. 9, 2008]



 Sec. Appendix O to Part 50--Reference Method for the Determination of 
         Coarse Particulate Matter as PM10-2.5 in the Atmosphere

                    1.0 Applicability and Definition

    1.1 This method provides for the measurement of the mass 
concentration of coarse particulate matter (PM10-2.5) in 
ambient air over a 24-hour period. In conjunction with additional 
analysis, this method may be used to develop speciated data.
    1.2 For the purpose of this method, PM10-2.5 is defined 
as particulate matter having an aerodynamic diameter in the nominal 
range of 2.5 to 10 micrometers, inclusive.
    1.3 For this reference method, PM10-2.5 concentrations 
shall be measured as the arithmetic difference between separate but 
concurrent, collocated measurements of PM10 and 
PM2.5, where the PM10 measurements are obtained 
with a specially approved sampler, identified as a ``PM10c 
sampler,'' that meets more demanding performance requirements than 
conventional PM10 samplers described in appendix J of this 
part. Measurements obtained with a PM10c sampler are 
identified as ``PM10c measurements'' to distinguish them from 
conventional PM10 measurements obtained with conventional 
PM10 samplers. Thus, PM10-2.5 = PM10c - 
PM2.5.
    1.4 The PM10c and PM2.5 gravimetric 
measurement processes are considered to be nondestructive, and the 
PM10c and PM2.5 samples obtained in the 
PM10-2.5 measurement process can be subjected to subsequent 
physical or chemical analyses.
    1.5 Quality assessment procedures are provided in part 58, appendix 
A of this chapter. The quality assurance procedures and guidance 
provided in reference 1 in section 13 of this appendix, although written 
specifically for PM2.5, are generally applicable for 
PM10c, and, hence, PM10-2.5 measurements under 
this method, as well.
    1.6 A method based on specific model PM10c and 
PM2.5 samplers will be considered a reference method for 
purposes of part 58 of this chapter only if:
    (a) The PM10c and PM2.5 samplers and the 
associated operational procedures meet the requirements specified in 
this appendix and all applicable requirements in part 53 of this 
chapter, and
    (b) The method based on the specific samplers and associated 
operational procedures have been designated as a reference method in 
accordance with part 53 of this chapter.
    1.7 PM10-2.5 methods based on samplers that meet nearly 
all specifications set forth in this method but have one or more 
significant but minor deviations or modifications from those 
specifications may be designated as ``Class I'' equivalent methods for 
PM10-2.5 in accordance with part 53 of this chapter.
    1.8 PM2.5 measurements obtained incidental to the 
PM10-2.5 measurements by this method shall be considered to 
have been obtained with a reference method for PM2.5 in 
accordance with appendix L of this part.
    1.9 PM10c measurements obtained incidental to the 
PM10-2.5 measurements by this method shall be considered to 
have been obtained with a reference method for PM10 in 
accordance with appendix J of this part, provided that:
    (a) The PM10c measurements are adjusted to EPA reference 
conditions (25 [deg]C and 760 millimeters of mercury), and
    (b) Such PM10c measurements are appropriately identified 
to differentiate them from PM10 measurements obtained with 
other (conventional) methods for PM10 designated in 
accordance with part 53 of this

[[Page 125]]

chapter as reference or equivalent methods for PM10.

                              2.0 Principle

    2.1 Separate, collocated, electrically powered air samplers for 
PM10c and PM2.5 concurrently draw ambient air at 
identical, constant volumetric flow rates into specially shaped inlets 
and through one or more inertial particle size separators where the 
suspended particulate matter in the PM10 or PM2.5 
size range, as applicable, is separated for collection on a 
polytetrafluoroethylene (PTFE) filter over the specified sampling 
period. The air samplers and other aspects of this PM10-2.5 
reference method are specified either explicitly in this appendix or by 
reference to other applicable regulations or quality assurance guidance.
    2.2 Each PM10c and PM2.5 sample collection 
filter is weighed (after moisture and temperature conditioning) before 
and after sample collection to determine the net weight (mass) gain due 
to collected PM10c or PM2.5. The total volume of 
air sampled by each sampler is determined by the sampler from the 
measured flow rate at local ambient temperature and pressure and the 
sampling time. The mass concentrations of both PM10c and 
PM2.5 in the ambient air are computed as the total mass of 
collected particles in the PM10 or PM2.5 size 
range, as appropriate, divided by the total volume of air sampled by the 
respective samplers, and expressed in micrograms per cubic meter 
([micro]g/m\3\)at local temperature and pressure conditions. The mass 
concentration of PM10-2.5 is determined as the 
PM10c concentration value less the corresponding, 
concurrently measured PM2.5 concentration value.
    2.3 Most requirements for PM10-2.5 reference methods are 
similar or identical to the requirements for PM2.5 reference 
methods as set forth in appendix L to this part. To insure uniformity, 
applicable appendix L requirements are incorporated herein by reference 
in the sections where indicated rather than repeated in this appendix.

                     3.0 PM10	2.5 Measurement Range

    3.1 Lower concentration limit. The lower detection limit of the mass 
concentration measurement range is estimated to be approximately 3 
[micro]g/m\3\, based on the observed precision of PM2.5 
measurements in the national PM2.5 monitoring network, the 
probable similar level of precision for the matched PM10c 
measurements, and the additional variability arising from the 
differential nature of the measurement process. This value is provided 
merely as a guide to the significance of low PM10-2.5 
concentration measurements.
    3.2 Upper concentration limit. The upper limit of the mass 
concentration range is determined principally by the PM10c 
filter mass loading beyond which the sampler can no longer maintain the 
operating flow rate within specified limits due to increased pressure 
drop across the loaded filter. This upper limit cannot be specified 
precisely because it is a complex function of the ambient particle size 
distribution and type, humidity, the individual filter used, the 
capacity of the sampler flow rate control system, and perhaps other 
factors. All PM10c samplers are estimated to be capable of 
measuring 24-hour mass concentrations of at least 200 [micro]g/m\3\ 
while maintaining the operating flow rate within the specified limits. 
The upper limit for the PM10-2.5 measurement is likely to be 
somewhat lower because the PM10-2.5 concentration represents 
only a fraction of the PM10 concentration.
    3.3 Sample period. The required sample period for 
PM10-2.5 concentration measurements by this method shall be 
at least 1,380 minutes but not more than 1,500 minutes (23 to 25 hours), 
and the start times of the PM2.5 and PM10c samples 
are within 10 minutes and the stop times of the samples are also within 
10 minutes (see section 10.4 of this appendix).

                           4.0 Accuracy (bias)

    4.1 Because the size, density, and volatility of the particles 
making up ambient particulate matter vary over wide ranges and the mass 
concentration of particles varies with particle size, it is difficult to 
define the accuracy of PM10-2.5 measurements in an absolute 
sense. Furthermore, generation of credible PM10-2.5 
concentration standards at field monitoring sites and presenting or 
introducing such standards reliably to samplers or monitors to assess 
accuracy is still generally impractical. The accuracy of 
PM10-2.5 measurements is therefore defined in a relative 
sense as bias, referenced to measurements provided by other reference 
method samplers or based on flow rate verification audits or checks, or 
on other performance evaluation procedures.
    4.2 Measurement system bias for monitoring data is assessed 
according to the procedures and schedule set forth in part 58, appendix 
A of this chapter. The goal for the measurement uncertainty (as bias) 
for monitoring data is defined in part 58, appendix A of this chapter as 
an upper 95 percent confidence limit for the absolute bias of 15 
percent. Reference 1 in section 13 of this appendix provides additional 
information and guidance on flow rate accuracy audits and assessment of 
bias.

                              5.0 Precision

    5.1 Tests to establish initial measurement precision for each 
sampler of the reference method sampler pair are specified as a part of 
the requirements for designation as a reference method under part 53 of 
this chapter.

[[Page 126]]

    5.2 Measurement system precision is assessed according to the 
procedures and schedule set forth in appendix A to part 58 of this 
chapter. The goal for acceptable measurement uncertainty, as precision, 
of monitoring data is defined in part 58, appendix A of this chapter as 
an upper 95 percent confidence limit for the coefficient of variation 
(CV) of 15 percent. Reference 1 in section 13 of this appendix provides 
additional information and guidance on this requirement.
    6.0 Filters for PM10c and PM2.5 Sample 
Collection. Sample collection filters for both PM10c and 
PM2.5 measurements shall be identical and as specified in 
section 6 of appendix L to this part.
    7.0 Sampler. The PM10-2.5 sampler shall consist of a 
PM10c sampler and a PM2.5 sampler, as follows:
    7.1 The PM2.5 sampler shall be as specified in section 7 
of appendix L to this part.
    7.2 The PM10c sampler shall be of like manufacturer, 
design, configuration, and fabrication to that of the PM2.5 
sampler and as specified in section 7 of appendix L to this part, except 
as follows:
    7.2.1 The particle size separator specified in section 7.3.4 of 
appendix L to this part shall be eliminated and replaced by a downtube 
extension fabricated as specified in Figure O-1 of this appendix.
    7.2.2 The sampler shall be identified as a PM10c sampler 
on its identification label required under Sec. 53.9(d) of this 
chapter.
    7.2.3 The average temperature and average barometric pressure 
measured by the sampler during the sample period, as described in Table 
L-1 of appendix L to this part, need not be reported to EPA's AQS data 
base, as required by section 7.4.19 and Table L-1 of appendix L to this 
part, provided such measurements for the sample period determined by the 
associated PM2.5 sampler are reported as required.
    7.3 In addition to the operation/instruction manual required by 
section 7.4.18 of appendix L to this part for each sampler, supplemental 
operational instructions shall be provided for the simultaneous 
operation of the samplers as a pair to collect concurrent 
PM10c and PM2.5 samples. The supplemental 
instructions shall cover any special procedures or guidance for 
installation and setup of the samplers for PM10-2.5 
measurements, such as synchronization of the samplers' clocks or timers, 
proper programming for collection of concurrent samples, and any other 
pertinent issues related to the simultaneous, coordinated operation of 
the two samplers.
    7.4 Capability for electrical interconnection of the samplers to 
simplify sample period programming and further ensure simultaneous 
operation is encouraged but not required. Any such capability for 
interconnection shall not supplant each sampler's capability to operate 
independently, as required by section 7 of appendix L of this part.

                           8.0 Filter Weighing

    8.1 Conditioning and weighing for both PM10c and 
PM2.5 sample filters shall be as specified in section 8 of 
appendix L to this part. See reference 1 of section 13 of this appendix 
for additional, more detailed guidance.
    8.2 Handling, conditioning, and weighing for both PM10c 
and PM2.5 sample filters shall be matched such that the 
corresponding PM10c and PM2.5 filters of each 
filter pair receive uniform treatment. The PM10c and 
PM2.5 sample filters should be weighed on the same balance, 
preferably in the same weighing session and by the same analyst.
    8.3 Due care shall be exercised to accurately maintain the paired 
relationship of each set of concurrently collected PM10c and 
PM2.5 sample filters and their net weight gain data and to 
avoid misidentification or reversal of the filter samples or weight 
data. See Reference 1 of section 13 of this appendix for additional 
guidance.
    9.0 Calibration. Calibration of the flow rate, temperature 
measurement, and pressure measurement systems for both the 
PM10c and PM2.5 samplers shall be as specified in 
section 9 of appendix L to this part.

                   10.0 PM10	2.5 Measurement Procedure

    10.1 The PM10c and PM2.5 samplers shall be 
installed at the monitoring site such that their ambient air inlets 
differ in vertical height by not more than 0.2 meter, if possible, but 
in any case not more than 1 meter, and the vertical axes of their inlets 
are separated by at least 1 meter but not more than 4 meters, 
horizontally.
    10.2 The measurement procedure for PM10c shall be as 
specified in section 10 of appendix L to this part, with 
``PM10c'' substituted for ``PM2.5'' wherever it 
occurs in that section.
    10.3 The measurement procedure for PM2.5 shall be as 
specified in section 10 of appendix L to this part.
    10.4 For the PM10-2.5 measurement, the PM10c 
and PM2.5 samplers shall be programmed to operate on the same 
schedule and such that the sample period start times are within 5 
minutes and the sample duration times are within 5 minutes.
    10.5 Retrieval, transport, and storage of each PM10c and 
PM2.5 sample pair following sample collection shall be 
matched to the extent practical such that both samples experience 
uniform conditions.
    11.0 Sampler Maintenance. Both PM10c and PM2.5 
samplers shall be maintained as described in section 11 of appendix L to 
this part.

[[Page 127]]

                            12.0 Calculations

    12.1 Both concurrent PM10c and PM2.5 
measurements must be available, valid, and meet the conditions of 
section 10.4 of this appendix to determine the PM10-2.5 mass 
concentration.
    12.2 The PM10c mass concentration is calculated using 
equation 1 of this section:
[GRAPHIC] [TIFF OMITTED] TR17OC06.012

Where:

PM10c = mass concentration of PM10c, [micro]g/
m\3\;
Wf, Wi = final and initial masses (weights), 
respectively, of the filter used to collect the PM10c 
particle sample, [micro]g;
Va = total air volume sampled by the PM10c sampler 
in actual volume units measured at local conditions of temperature and 
pressure, as provided by the sampler, m\3\.

    Note: Total sample time must be between 1,380 and 1,500 minutes (23 
and 25 hrs) for a fully valid PM10c sample; however, see also 
section 3.3 of this appendix.

    12.3 The PM2.5 mass concentration is calculated as 
specified in section 12 of appendix L to this part.
    12.4 The PM10-2.5 mass concentration, in [micro]g/m\3\, 
is calculated using Equation 2 of this section:
[GRAPHIC] [TIFF OMITTED] TR17OC06.013

                             13.0 Reference

    1. Quality Assurance Guidance Document 2.12. Monitoring 
PM2.5 in Ambient Air Using Designated Reference or Class I 
Equivalent Methods. Draft, November 1998 (or later version or 
supplement, if available). Available at: www.epa.gov/ttn/amtic/
pgqa.html.

                              14.0 Figures

    Figure O-1 is included as part of this appendix O.

[[Page 128]]

[GRAPHIC] [TIFF OMITTED] TR17OC06.014


[[Page 129]]



[71 FR 61230, Oct. 17, 2006]



Sec. Appendix P to Part 50--Interpretation of the Primary and Secondary 
            National Ambient Air Quality Standards for Ozone

                               1. General

    (a) This appendix explains the data handling conventions and 
computations necessary for determining whether the national 8-hour 
primary and secondary ambient air quality standards for ozone (O3) 
specified in Sec. 50.15 are met at an ambient O3 air quality monitoring 
site. Ozone is measured in the ambient air by a reference method based 
on Appendix D of this part, as applicable, and designated in accordance 
with part 53 of this chapter, or by an equivalent method designated in 
accordance with part 53 of this chapter. Data reporting, data handling, 
and computation procedures to be used in making comparisons between 
reported O3 concentrations and the levels of the O3 standards are 
specified in the following sections. Whether to exclude, retain, or make 
adjustments to the data affected by exceptional events, including 
stratospheric O3 intrusion and other natural events, is determined by 
the requirements under Sec. Sec. 50.1, 50.14 and 51.930.
    (b) The terms used in this appendix are defined as follows:
    8-hour average is the rolling average of eight hourly O3 
concentrations as explained in section 2 of this appendix.
    Annual fourth-highest daily maximum refers to the fourth highest 
value measured at a monitoring site during a particular year.
    Daily maximum 8-hour average concentration refers to the maximum 
calculated 8-hour average for a particular day as explained in section 2 
of this appendix.
    Design values are the metrics (i.e., statistics) that are compared 
to the NAAQS levels to determine compliance, calculated as shown in 
section 3 of this appendix.
    O3 monitoring season refers to the span of time within a 
calendar year when individual States are required to measure ambient 
O3 concentrations as listed in part 58 Appendix D to this 
chapter.
    Year refers to calendar year.

    2. Primary and Secondary Ambient Air Quality Standards for Ozone

               2.1 Data Reporting and Handling Conventions

    Computing 8-hour averages. Hourly average concentrations shall be 
reported in parts per million (ppm) to the third decimal place, with 
additional digits to the right of the third decimal place truncated. 
Running 8-hour averages shall be computed from the hourly O3 
concentration data for each hour of the year and shall be stored in the 
first, or start, hour of the 8-hour period. An 8-hour average shall be 
considered valid if at least 75% of the hourly averages for the 8-hour 
period are available. In the event that only 6 or 7 hourly averages are 
available, the 8-hour average shall be computed on the basis of the 
hours available using 6 or 7 as the divisor. 8-hour periods with three 
or more missing hours shall be considered valid also, if, after 
substituting one-half the minimum detectable limit for the missing 
hourly concentrations, the 8-hour average concentration is greater than 
the level of the standard. The computed 8-hour average O3 
concentrations shall be reported to three decimal places (the digits to 
the right of the third decimal place are truncated, consistent with the 
data handling procedures for the reported data).
    Daily maximum 8-hour average concentrations. (a) There are 24 
possible running 8-hour average O3 concentrations for each 
calendar day during the O3 monitoring season. The daily 
maximum 8-hour concentration for a given calendar day is the highest of 
the 24 possible 8-hour average concentrations computed for that day. 
This process is repeated, yielding a daily maximum 8-hour average 
O3 concentration for each calendar day with ambient 
O3 monitoring data. Because the 8-hour averages are recorded 
in the start hour, the daily maximum 8-hour concentrations from two 
consecutive days may have some hourly concentrations in common. 
Generally, overlapping daily maximum 8-hour averages are not likely, 
except in those non-urban monitoring locations with less pronounced 
diurnal variation in hourly concentrations.
    (b) An O3 monitoring day shall be counted as a valid day 
if valid 8-hour averages are available for at least 75% of possible 
hours in the day (i.e., at least 18 of the 24 averages). In the event 
that less than 75% of the 8-hour averages are available, a day shall 
also be counted as a valid day if the daily maximum 8-hour average 
concentration for that day is greater than the level of the standard.

      2.2 Primary and Secondary Standard-related Summary Statistic

    The standard-related summary statistic is the annual fourth-highest 
daily maximum 8-hour O3 concentration, expressed in parts per 
million, averaged over three years. The 3-year average shall be computed 
using the three most recent, consecutive calendar years of monitoring 
data meeting the data completeness requirements described in this 
appendix. The computed 3-year average of the annual fourth-highest daily 
maximum 8-hour average O3 concentrations shall be reported to 
three decimal places (the digits to the right of the third decimal place 
are truncated, consistent with the data handling procedures for the 
reported data).

[[Page 130]]

     2.3 Comparisons with the Primary and Secondary Ozone Standards

    (a) The primary and secondary O3 ambient air quality 
standards are met at an ambient air quality monitoring site when the 3-
year average of the annual fourth-highest daily maximum 8-hour average 
O3 concentration is less than or equal to 0.075 ppm.
    (b) This comparison shall be based on three consecutive, complete 
calendar years of air quality monitoring data. This requirement is met 
for the 3-year period at a monitoring site if daily maximum 8-hour 
average concentrations are available for at least 90% of the days within 
the O3 monitoring season, on average, for the 3-year period, 
with a minimum data completeness requirement in any one year of at least 
75% of the days within the O3 monitoring season. When 
computing whether the minimum data completeness requirements have been 
met, meteorological or ambient data may be sufficient to demonstrate 
that meteorological conditions on missing days were not conducive to 
concentrations above the level of the standard. Missing days assumed 
less then the level of the standard are counted for the purpose of 
meeting the data completeness requirement, subject to the approval of 
the appropriate Regional Administrator.
    (c) Years with concentrations greater than the level of the standard 
shall be included even if they have less than complete data. Thus, in 
computing the 3-year average fourth maximum concentration, calendar 
years with less than 75% data completeness shall be included in the 
computation if the 3-year average fourth-highest 8-hour concentration is 
greater than the level of the standard.
    (d) Comparisons with the primary and secondary O3 
standards are demonstrated by examples 1 and 2 in paragraphs (d)(1) and 
(d)(2) respectively as follows:

                                  Example 1.--Ambient Monitoring Site Attaining the Primary and Secondary O3 Standards
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Percent valid
                                                           days (within     1st Highest     2nd Highest     3rd Highest     4th Highest     5th Highest
                          Year                             the required    daily max 8-    daily max 8-    daily max 8-    daily max 8-    daily max 8-
                                                            monitoring      hour Conc.      hour Conc.      hour Conc.      hour Conc.      hour Conc.
                                                              season)          (ppm)           (ppm)           (ppm)           (ppm)           (ppm)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2004....................................................             100           0.092           0.090           0.085           0.079           0.078
2005....................................................              96           0.084           0.083           0.075           0.072           0.070
2006....................................................              98           0.080           0.079           0.077           0.076           0.060
                                                         -----------------------------------------------------------------------------------------------
    Average.............................................              98  ..............  ..............  ..............           0.075  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (1) As shown in Example 1, this monitoring site meets the primary 
and secondary O3 standards because the 3-year average of the 
annual fourth-highest daily maximum 8-hour average O3 
concentrations (i.e., 0.075666 * * * ppm, truncated to 0.075 ppm) is 
less than or equal to 0.075 ppm. The data completeness requirement is 
also met because the average percent of days within the required 
monitoring season with valid ambient monitoring data is greater than 
90%, and no single year has less than 75% data completeness. In Example 
1, the individual 8-hour averages used to determine the annual fourth 
maximum have also been truncated to the third decimal place.

                               Example 2.--Ambient Monitoring Site Failing to Meet the Primary and Secondary O3 Standards
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Percent valid
                                                           days (within     1st Highest     2nd Highest     3rd Highest     4th Highest     5th Highest
                          Year                             the required    daily max 8-    daily max 8-    daily max 8-    daily max 8-    daily max 8-
                                                            monitoring      hour Conc.      hour Conc.      hour Conc.      hour Conc.      hour Conc.
                                                              season)          (ppm)           (ppm)           (ppm)           (ppm)           (ppm)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2004....................................................              96           0.105           0.103           0.103           0.103           0.102
2005....................................................              74           0.104           0.103           0.092           0.091           0.088
2006....................................................              98           0.103           0.101           0.101           0.095           0.094
                                                         -----------------------------------------------------------------------------------------------
    Average.............................................              89  ..............  ..............  ..............           0.096  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As shown in Example 2, the primary and secondary O3 
standards are not met for this monitoring site because the 3-year 
average of the fourth-highest daily maximum 8-hour average O3 
concentrations (i.e., 0.096333 * * * ppm, truncated to 0.096 ppm) is 
greater than 0.075 ppm, even though the data capture is less than 75% 
and the average data capture for the 3 years is less than 90% within the 
required monitoring season. In Example 2, the individual 8-hour averages 
used to determine

[[Page 131]]

the annual fourth maximum have also been truncated to the third decimal 
place.

3. Design Values for Primary and Secondary Ambient Air Quality Standards 
                                for Ozone

    The air quality design value at a monitoring site is defined as that 
concentration that when reduced to the level of the standard ensures 
that the site meets the standard. For a concentration-based standard, 
the air quality design value is simply the standard-related test 
statistic. Thus, for the primary and secondary standards, the 3-year 
average annual fourth-highest daily maximum 8-hour average O3 
concentration is also the air quality design value for the site.

[73 FR 16511, Mar. 27, 2008]



 Sec. Appendix Q to Part 50--Reference Method for the Determination of 
      Lead in Particulate Matter as PM10 Collected From Ambient Air

    This Federal Reference Method (FRM) draws heavily from the specific 
analytical protocols used by the U.S. EPA.
    1. Applicability and Principle
    1.1 This method provides for the measurement of the lead (Pb) 
concentration in particulate matter that is 10 micrometers or less 
(PM10) in ambient air. PM10 is collected on an 
acceptable (see section 6.1.2) 46.2 mm diameter polytetrafluoroethylene 
(PTFE) filter for 24 hours using active sampling at local conditions 
with a low-volume air sampler. The low-volume sampler has an average 
flow rate of 16.7 liters per minute (Lpm) and total sampled volume of 24 
cubic meters (m\3\) of air. The analysis of Pb in PM10 is 
performed on each individual 24-hour sample. Gravimetric mass analysis 
of PM10c filters is not required for Pb analysis. For the 
purpose of this method, PM10 is defined as particulate matter 
having an aerodynamic diameter in the nominal range of 10 micrometers 
(10 [micro]m) or less.
    1.2 For this reference method, PM10 shall be collected 
with the PM10c federal reference method (FRM) sampler as 
described in Appendix O to Part 50 using the same sample period, 
measurement procedures, and requirements specified in Appendix L of Part 
50. The PM10c sampler is also being used for measurement of 
PM10-2.5 mass by difference and as such, the PM10c 
sampler must also meet all of the performance requirements specified for 
PM2.5 in Appendix L. The concentration of Pb in the 
atmosphere is determined in the total volume of air sampled and 
expressed in micrograms per cubic meter ([micro]g/m\3\) at local 
temperature and pressure conditions.
    1.3 The FRM will serve as the basis for approving Federal Equivalent 
Methods (FEMs) as specified in 40 CFR Part 53 (Reference and Equivalent 
Methods). This FRM specifically applies to the analysis of Pb in 
PM10 filters collected with the PM10c sampler. If 
these filters are analyzed for elements other than Pb, then refer to the 
guidance provided in the EPA Inorganic Compendium Method IO-3.3 
(Reference 1 of section 8) for multi-element analysis.
    1.4 The PM10c air sampler draws ambient air at a constant 
volumetric flow rate into a specially shaped inlet and through an 
inertial particle size separator, where the suspended particulate matter 
in the PM10 size range is separated for collection on a PTFE 
filter over the specified sampling period. The Pb content of the 
PM10 sample is analyzed by energy-dispersive X-ray 
fluorescence spectrometry (EDXRF). Energy-dispersive X-ray fluorescence 
spectrometry provides a means for identification of an element by 
measurement of its characteristic X-ray emission energy. The method 
allows for quantification of the element by measuring the intensity of 
X-rays emitted at the characteristic photon energy and then relating 
this intensity to the elemental concentration. The number or intensity 
of X-rays produced at a given energy provides a measure of the amount of 
the element present by comparisons with calibration standards. The X-
rays are detected and the spectral signals are acquired and processed 
with a personal computer. EDXRF is commonly used as a non-destructive 
method for quantifying trace elements in PM. A detailed explanation of 
quantitative X-ray spectrometry is described in references 2, 3 and 4.
    1.5 Quality assurance (QA) procedures for the collection of 
monitoring data are contained in Part 58, Appendix A.
    2. PM10 Pb Measurement Range and Detection Limit. The values given 
below in section 2.1 and 2.2 are typical of the method capabilities. 
Absolute values will vary for individual situations depending on the 
instrument, detector age, and operating conditions used. Data are 
typically reported in ng/m\3\ for ambient air samples; however, for this 
reference method, data will be reported in [micro]g/m\3\ at local 
temperature and pressure conditions.
    2.1 EDXRF Pb Measurement Range. The typical ambient air measurement 
range is 0.001 to 30 [micro]g Pb/m\3\, assuming an upper range 
calibration standard of about 60 [micro]g Pb per square centimeter 
(cm\2\), a filter deposit area of 11.86 cm\2\, and an air volume of 24 
m\3\. The top range of the EDXRF instrument is much greater than what is 
stated here. The top measurement range of quantification is defined by 
the level of the high concentration calibration standard used and can be 
increased to expand the measurement range as needed.
    2.2 Detection Limit (DL). A typical estimate of the one-sigma 
detection limit (DL) is about 2 ng Pb/cm\2\ or 0.001 [micro]g Pb/m\3\, 
assuming a filter size of 46.2 mm (filter deposit

[[Page 132]]

area of 11.86 cm\2\) and a sample air volume of 24 m\3\. The DL is an 
estimate of the lowest amount of Pb that can be reliably distinguished 
from a blank filter. The one-sigma detection limit for Pb is calculated 
as the average overall uncertainty or propagated error for Pb, 
determined from measurements on a series of blank filters from the 
filter lot(s) in use. Detection limits must be determined for each 
filter lot in use. If a new filter lot is used, then a new DL must be 
determined. The sources of random error which are considered are 
calibration uncertainty; system stability; peak and background counting 
statistics; uncertainty in attenuation corrections; and uncertainty in 
peak overlap corrections, but the dominating source by far is peak and 
background counting statistics. At a minimum, laboratories are to 
determine annual estimates of the DL using the guidance provided in 
Reference 5.
    3. Factors Affecting Bias and Precision of Lead Determination by 
EDXRF
    3.1 Filter Deposit. X-ray spectra are subject to distortion if 
unusually heavy deposits are analyzed. This is the result of internal 
absorption of both primary and secondary X-rays within the sample; 
however, this is not an issue for Pb due to the energetic X-rays used to 
fluoresce Pb and the energetic characteristic X-rays emitted by Pb. The 
optimum mass filter loading for multi-elemental EDXRF analyis is about 
100 [micro]g/cm\2\ or 1.2 mg/filter for a 46.2-mm filter. Too little 
deposit material can also be problematic due to low counting statistics 
and signal noise. The particle mass deposit should minimally be 15 
[micro]g/cm\2\. The maximum PM10 filter loading or upper 
concentration limit of mass expected to be collected by the 
PM10c sampler is 200 [micro]g/m\3\ (Appendix O to Part 50, 
Section 3.2). This equates to a mass loading of about 400 [micro]g/cm\2\ 
and is the maximum expected loading for PM10c filters. This 
maximum loading is acceptable for the analysis of Pb and other high-Z 
elements with very energetic characteristic X-rays. A properly collected 
sample will have a uniform deposit over the entire collection area. 
Samples with physical deformities (including a visually non-uniform 
deposit area) should not be quantitatively analyzed. Tests on the 
uniformity of particle deposition on PM10C filters showed 
that the non-uniformity of the filter deposit represents a small 
fraction of the overall uncertainty in ambient Pb concentration 
measurement. The analysis beam of the XRF analyzer does not cover the 
entire filter collection area. The minimum allowable beam size is 10 mm.
    3.2 Spectral Interferences and Spectral Overlap. Spectral 
interference occurs when the entirety of the analyte spectral lines of 
two species are nearly 100% overlapped. The presence of arsenic (As) is 
a problematic interference for EDXRF systems which use the Pb L[alpha] 
line exclusively to quantify the Pb concentration. This is because the 
Pb L[alpha] line and the As K[alpha] lines severely overlap. The use of 
multiple Pb lines, including the L[beta] and/or the L[gamma] lines for 
quantification must be used to reduce the uncertainty in the Pb 
determination in the presence of As. There can be instances when lines 
partially overlap the Pb spectral lines, but with the energy resolution 
of most detectors these overlaps are typically de-convoluted using 
standard spectral de-convolution software provided by the instrument 
vendor. An EDXRF protocol for Pb must define which Pb lines are used for 
quantification and where spectral overlaps occur. A de-convolution 
protocol must be used to separate all the lines which overlap with Pb.
    3.3 Particle Size Effects and Attenuation Correction Factors. X-ray 
attenuation is dependent on the X-ray energy, mass sample loading, 
composition, and particle size. In some cases, the excitation and 
fluorescent X-rays are attenuated as they pass through the sample. In 
order to relate the measured intensity of the X-rays to the thin-film 
calibration standards used, the magnitude of any attenuation present 
must be corrected for. See references 6, 7, and 8 for more discussion on 
this issue. Essentially no attenuation corrections are necessary for Pb 
in PM10: Both the incoming excitation X-rays used for 
analyzing lead and the fluoresced Pb X-rays are sufficiently energetic 
that for particles in this size range and for normal filter loadings, 
the Pb X-ray yield is not significantly impacted by attenuation.
    4. Precision
    4.1 Measurement system precision is assessed according to the 
procedures set forth in Appendix A to part 58. Measurement method 
precision is assessed from collocated sampling and analysis. The goal 
for acceptable measurement uncertainty, as precision, is defined as an 
upper 90 percent confidence limit for the coefficient of variation (CV) 
of 20 percent.
    5. Bias
    5.1 Measurement system bias for monitoring data is assessed 
according to the procedures set forth in Appendix A of part 58. The bias 
is assessed through an audit using spiked filters. The goal for 
measurement bias is defined as an upper 95 percent confidence limit for 
the absolute bias of 15 percent.
    6. Measurement of PTFE Filters by EDXRF
    6.1 Sampling
    6.1.1 Low-Volume PM10c Sampler. The low-volume PM10c 
sampler shall be used for PM10 sample collection and operated 
in accordance with the performance specifications described in Part 50, 
Appendix L.
    6.1.2 PTFE Filters and Filter Acceptance Testing. The PTFE filters 
used for PM10c sample collection shall meet the 
specifications provided in Part 50, Appendix L. The following 
requirements are similar to those

[[Page 133]]

currently specified for the acceptance of PM2.5 filters that 
are tested for trace elements by EDXRF. For large filter lots (greater 
than 500 filters) randomly select 20 filters from a given lot. For small 
lots (less than 500 filters) a lesser number of filters may be taken. 
Analyze each blank filter separately and calculate the average lead 
concentration in ng/cm\2\. Ninety percent, or 18 of the 20 filters, must 
have an average lead concentration that is less than 4.8 ng Pb/cm\2\.
    6.1.2.1 Filter Blanks. Field blank filters shall be collected along 
with routine samples. Field blank filters will be collected that are 
transported to the sampling site and placed in the sampler for the 
duration of sampling without sampling. Laboratory blank filters from 
each filter lot used shall be analyzed with each batch of routine sample 
filters analyzed. Laboratory blank filters are used in background 
subtraction as discussed below in Section 6.2.4.
    6.2 Analysis. The four main categories of random and systematic 
error encountered in X-ray fluorescence analysis include errors from 
sample collection, the X-ray source, the counting process, and inter-
element effects. These errors are addressed through the calibration 
process and mathematical corrections in the instrument software. 
Spectral processing methods are well established and most commercial 
analyzers have software that can implement the most common approaches 
(references 9-11) to background subtraction, peak overlap correction, 
counting and deadtime corrections.
    6.2.1 EDXRF Analysis Instrument. An energy-dispersive XRF system is 
used. Energy-dispersive XRF systems are available from a number of 
commercial vendors. Examples include Thermo (www.thermo.com), Spectro 
(http://www.spectro.com), Xenemetrix (http://www.xenemetrix.com) and 
PANalytical (http://www.panalytical.com). \1\ The analysis is performed 
at room temperature in either vacuum or in a helium atmosphere. The 
specific details of the corrections and calibration algorithms are 
typically included in commercial analytical instrument software routines 
for automated spectral acquisition and processing and vary by 
manufacturer. It is important for the analyst to understand the 
correction procedures and algorithms of the particular system used, to 
ensure that the necessary corrections are applied.
---------------------------------------------------------------------------

    \1\ These are examples of available systems and is not an all 
inclusive list. The mention of commercial products does not imply 
endorsement by the U.S. Environmental Protection Agency.
---------------------------------------------------------------------------

    6.2.2 Thin film standards. Thin film standards are used for 
calibration because they most closely resemble the layer of particles on 
a filter. Thin films standards are typically deposited on Nuclepore 
substrates. The preparation of thin film standards is discussed in 
reference 8, and 10. The NIST SRM 2783 (Air Particulate on Filter Media) 
is currently available on polycarbonate filters and contains a certified 
concentration for Pb. Thin film standards at 15 and 50 [micro]g/cm\2\ 
are commercially available from MicroMatter Inc. (Arlington, WA).
    6.2.3 Filter Preparation. Filters used for sample collection are 
46.2-mm PTFE filters with a pore size of 2 microns and filter deposit 
area 11.86 cm\2\. Cold storage is not a requirement for filters analyzed 
for Pb; however, if filters scheduled for XRF analysis were stored cold, 
they must be allowed to reach room temperature prior to analysis. All 
filter samples received for analysis are checked for any holes, tears, 
or a non-uniform deposit which would prevent quantitative analysis. 
Samples with physical deformities are not quantitatively analyzable. The 
filters are carefully removed with tweezers from the Petri dish and 
securely placed into the instrument-specific sampler holder for 
analysis. Care must be taken to protect filters from contamination prior 
to analysis. Filters must be kept covered when not being analyzed. No 
other preparation of filter samples is required.
    6.2.4 Calibration. In general, calibration determines each element's 
sensitivity, i.e., its response in x-ray counts/sec to each [micro]g/
cm\2\ of a standard and an interference coefficient for each element 
that causes interference with another one (See section 3.2 above). The 
sensitivity can be determined by a linear plot of count rate versus 
concentration ([micro]g/cm\2\) in which the slope is the instrument's 
sensitivity for that element. A more precise way, which requires fewer 
standards, is to fit sensitivity versus atomic number. Calibration is a 
complex task in the operation of an XRF system. Two major functions 
accomplished by calibration are the production of reference spectra 
which are used for fitting and the determination of the elemental 
sensitivities. Included in the reference spectra (referred to as 
``shapes'') are background-subtracted peak shapes of the elements to be 
analyzed (as well as interfering elements) and spectral backgrounds. 
Pure element thin film standards are used for the element peak shapes 
and clean filter blanks from the same lot as routine filter samples are 
used for the background. The analysis of Pb in PM filter deposits is 
based on the assumption that the thickness of the deposit is small with 
respect to the characteristic Pb X-ray transmission thickness. 
Therefore, the concentration of Pb in a sample is determined by first 
calibrating the spectrometer with thin film standards to determine the 
sensitivity factor for Pb and then analyzing the unknown samples under 
identical excitation conditions as used to determine the calibration. 
Calibration shall be

[[Page 134]]

performed annually or when significant repairs or changes occur (e.g., a 
change in fluorescers, X-ray tubes, or detector). Calibration 
establishes the elemental sensitivity factors and the magnitude of 
interference or overlap coefficients. See reference 7 for more detailed 
discussion of calibration and analysis of shapes standards for 
background correction, coarse particle absorption corrections, and 
spectral overlap.
    6.2.4.1 Spectral Peak Fitting. The EPA uses a library of pure 
element peak shapes (shape standards) to extract the elemental 
background-free peak areas from an unknown spectrum. It is also possible 
to fit spectra using peak stripping or analytically defined functions 
such as modified Gaussian functions. The EPA shape standards are 
generated from pure, mono-elemental thin film standards. The shape 
standards are acquired for sufficiently long times to provide a large 
number of counts in the peaks of interest. It is not necessary for the 
concentration of the standard to be known. A slight contaminant in the 
region of interest in a shape standard can have a significant and 
serious effect on the ability of the least squares fitting algorithm to 
fit the shapes to the unknown spectrum. It is these elemental peak 
shapes that are fitted to the peaks in an unknown sample during spectral 
processing by the analyzer. In addition to this library of elemental 
shapes there is also a background shape spectrum for the filter type 
used as discussed below in section 6.2.4.2 of this section.
    6.2.4.2 Background Measurement and Correction. A background spectrum 
generated by the filter itself must be subtracted from the X-ray 
spectrum prior to extracting peak areas. Background spectra must be 
obtained for each filter lot used for sample collection. The background 
shape standards which are used for background fitting are created at the 
time of calibration. If a new lot of filters is used, new background 
spectra must be obtained. A minimum of 20 clean blank filters from each 
filter lot are kept in a sealed container and are used exclusively for 
background measurement and correction. The spectra acquired on 
individual blank filters are added together to produce a single spectrum 
for each of the secondary targets or fluorescers used in the analysis of 
lead. Individual blank filter spectra which show atypical contamination 
are excluded from the summed spectra. The summed spectra are fitted to 
the appropriate background during spectral processing. Background 
correction is automatically included during spectral processing of each 
sample.
    7. Calculation.
    7.1 PM10 Pb concentrations. The PM10 Pb concentration in 
the atmosphere ([micro]g/m\3\) is calculated using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR12NO08.000

Where,

MPb is the mass per unit volume for lead in [micro]g/m\3\;
CPb is the mass per unit area for lead in [micro]g/cm\2\ as measured by 
XRF;
A is the filter deposit area in cm\2\;
VLC is the total volume of air sampled by the PM10c sampler 
in actual volume units measured at local conditions of temperature and 
pressure, as provided by the sampler in m\3\.

    7.2 PM10 Pb Uncertainty Calculations.
    The principal contributors to total uncertainty of XRF values 
include: field sampling; filter deposit area; XRF calibration; 
attenuation or loss of the x-ray signals due to the other components of 
the particulate sample; and determination of the Pb X-ray emission peak 
area by curve fitting. See reference 12 for a detailed discussion of how 
uncertainties are similarly calculated for the PM2.5 Chemical 
Speciation program.
    The model for calculating total uncertainty is:

[delta]tot = ([delta]f2 + [delta]a2 + [delta]c2 + [delta]v2) 1/2

Where,

[delta]f = fitting uncertainty (XRF-specific, from 2 to 
100+%)
[delta]a = attenuation uncertainty (XRF-specific, 
insignificant for Pb)
[delta]c = calibration uncertainty (combined lab uncertainty, 
assumed as 5%)
[delta]v = volume/deposition size uncertainty (combined field 
uncertainty, assumed as 5%)

    8. References
    1. Inorganic Compendium Method IO-3.3; Determination of Metals in 
Ambient Particulate Matter Using X-Ray Fluorescence (XRF) Spectroscopy; 
U.S. Environmental Protection Agency, Cincinnati, OH 45268. EPA/625/R-
96/010a. June 1999.
    2. Jenkins, R., Gould, R.W., and Gedcke, D. Quantitative X-ray 
Spectrometry: Second Edition. Marcel Dekker, Inc., New York, NY. 1995.
    3. Jenkins, R. X-Ray Fluorescence Spectrometry: Second Edition in 
Chemical Analysis, a Series of Monographs on Analytical Chemistry and 
Its Applications, Volume 152. Editor J.D.Winefordner; John Wiley & Sons, 
Inc., New York, NY. 1999.
    4. Dzubay, T.G. X-ray Fluorescence Analysis of Environmental 
Samples, Ann Arbor Science Publishers Inc., 1977.
    5. Code of Federal Regulations (CFR) 40, Part 136, Appendix B; 
Definition and Procedure for the Determination of the Method Detection 
Limit--Revision 1.1.
    6. Drane, E.A, Rickel, D.G., and Courtney, W.J., ``Computer Code for 
Analysis X-Ray

[[Page 135]]

Fluorescence Spectra of Airborne Particulate Matter,'' in Advances in X-
Ray Analysis, J.R. Rhodes, Ed., Plenum Publishing Corporation, New York, 
NY, p. 23 (1980).
    7. Analysis of Energy-Dispersive X-ray Spectra of Ambient Aerosols 
with Shapes Optimization, Guidance Document; TR-WDE-06-02; prepared 
under contract EP-D-05-065 for the U.S. Environmental Protection Agency, 
National Exposure Research Laboratory. March 2006.
    8. Billiet, J., Dams, R., and Hoste, J. (1980) Multielement Thin 
Film Standards for XRF Analysis, X-Ray Spectrometry, 9(4): 206-211.
    9. Bonner, N.A.; Bazan, F.; and Camp, D.C. (1973). Elemental 
analysis of air filter samples using x-ray fluorescence. Report No. 
UCRL-51388. Prepared for U.S. Atomic Energy Commission, by Univ. of 
Calif., Lawrence Livermore Laboratory, Livermore, CA.
    10. Dzubay, T.G.; Lamothe, P.J.; and Yoshuda, H. (1977). Polymer 
films as calibration standards for X-ray fluorescence analysis. Adv. X-
Ray Anal., 20:411.
    11. Giauque, R.D.; Garrett, R.B.; and Goda, L.Y. (1977). Calibration 
of energy-dispersive X-ray spectrometers for analysis of thin 
environmental samples. In X-Ray Fluorescence Analysis of Environmental 
Samples, T.G. Dzubay, Ed., Ann Arbor Science Publishers, Ann Arbor, MI, 
pp. 153-181.
    12. Harmonization of Interlaboratory X-ray Fluorescence Measurement 
Uncertainties, Detailed Discussion Paper; August 4, 2006; prepared for 
the Office of Air Quality Planning and Standards under EPA contract 68-
D-03-038. http://www.epa.gov/ttn/amtic/files/ambient/pm25/spec/
xrfdet.pdf.

[73 FR 67052, Nov. 12, 2008]



 Sec. Appendix R to Part 50--Interpretation of the National Ambient Air 
                       Quality Standards for Lead

                               1. General.

    (a) This appendix explains the data handling conventions and 
computations necessary for determining when the primary and secondary 
national ambient air quality standards (NAAQS) for lead (Pb) specified 
in Sec. 50.16 are met. The NAAQS indicator for Pb is defined as: lead 
and its compounds, measured as elemental lead in total suspended 
particulate (Pb-TSP), sampled and analyzed by a Federal reference method 
(FRM) based on appendix G to this part or by a Federal equivalent method 
(FEM) designated in accordance with part 53 of this chapter. Although 
Pb-TSP is the lead NAAQS indicator, surrogate Pb-TSP concentrations 
shall also be used for NAAQS comparisons; specifically, valid surrogate 
Pb-TSP data are concentration data for lead and its compounds, measured 
as elemental lead, in particles with an aerodynamic size of 10 microns 
or less (Pb-PM10), sampled and analyzed by an FRM based on 
appendix Q to this part or by an FEM designated in accordance with part 
53 of this chapter. Surrogate Pb-TSP data (i.e., Pb-PM10 
data), however, can only be used to show that the Pb NAAQS were violated 
(i.e., not met); they can not be used to demonstrate that the Pb NAAQS 
were met. Pb-PM10 data used as surrogate Pb-TSP data shall be 
processed at face value; that is, without any transformation or scaling. 
Data handling and computation procedures to be used in making 
comparisons between reported and/or surrogate Pb-TSP concentrations and 
the level of the Pb NAAQS are specified in the following sections.
    (b) Whether to exclude, retain, or make adjustments to the data 
affected by exceptional events, including natural events, is determined 
by the requirements and process deadlines specified in Sec. Sec. 50.1, 
50.14, and 51.930 of this chapter.
    (c) The terms used in this appendix are defined as follows:
    Annual monitoring network plan refers to the plan required by 
section 58.10 of this chapter.
    Creditable samples are samples that are given credit for data 
completeness. They include valid samples collected on required sampling 
days and valid ``make-up'' samples taken for missed or invalidated 
samples on required sampling days.
    Daily values for Pb refer to the 24-hour mean concentrations of Pb 
(Pb-TSP or Pb-PM10), measured from midnight to midnight 
(local standard time), that are used in NAAQS computations.
    Design value is the site-level metric (i.e., statistic) that is 
compared to the NAAQS level to determine compliance; the design value 
for the Pb NAAQS is selected according to the procedures in this 
appendix from among the valid three-month Pb-TSP and surrogate Pb-TSP 
(Pb-PM10) arithmetic mean concentration for the 38-month 
period consisting of the most recent 3-year calendar period plus two 
previous months (i.e., 36 3-month periods) using the last month of each 
3-month period as the period of report.
    Extra samples are non-creditable samples. They are daily values that 
do not occur on scheduled sampling days and that can not be used as 
``make-up samples'' for missed or invalidated scheduled samples. Extra 
samples are used in mean calculations. For purposes of determining 
whether a sample must be treated as a make-up sample or an extra sample, 
Pb-TSP and Pb-PM10 data collected before January 1, 2009 will 
be treated with an assumed scheduled sampling frequency of every sixth 
day.
    Make-up samples are samples taken to replace missed or invalidated 
required scheduled samples. Make-ups can be made by either the primary 
or collocated (same size fraction) instruments; to be considered a

[[Page 136]]

valid make-up, the sampling must be conducted with equipment and 
procedures that meet the requirements for scheduled sampling. Make-up 
samples are either taken before the next required sampling day or 
exactly one week after the missed (or voided) sampling day. Make-up 
samples can not span years; that is, if a scheduled sample for December 
is missed (or voided), it can not be made up in January. Make-up 
samples, however, may span months, for example a missed sample on 
January 31 may be made up on February 1, 2, 3, 4, 5, or 7 (with an 
assumed sampling frequency of every sixth day). Section 3(e) explains 
how such month-spanning make-up samples are to be treated for purposes 
of data completeness and mean calculations. Only two make-up samples are 
permitted each calendar month; these are counted according to the month 
in which the miss and not the makeup occurred. For purposes of 
determining whether a sample must be treated as a make-up sample or an 
extra sample, Pb-TSP and Pb-PM10 data collected before 
January 1, 2009 will be treated with an assumed scheduled sampling 
frequency of every sixth day.
    Monthly mean refers to an arithmetic mean, calculated as specified 
in section 6(a) of this appendix. Monthly means are computed at each 
monitoring site separately for Pb-TSP and Pb-PM10 (i.e., by 
site-parameter-year-month).
    Parameter refers either to Pb-TSP or to Pb-PM10.
    Pollutant Occurrence Code (POC) refers to a numerical code (1, 2, 3, 
etc.) used to distinguish the data from two or more monitors for the 
same parameter at a single monitoring site.
    Scheduled sampling day means a day on which sampling is scheduled 
based on the required sampling frequency for the monitoring site, as 
provided in section 58.12 of this chapter.
    Three-month means are arithmetic averages of three consecutive 
monthly means. Three-month means are computed on a rolling, overlapping 
basis. Each distinct monthly mean will be included in three different 3-
month means; for example, in a given year, a November mean would be 
included in: (1) The September-October-November 3-month mean, (2) the 
October-November-December 3-month mean, and (3) the November-December-
January(of the following year) 3-month mean. Three-month means are 
computed separately for each parameter per section 6(a) (and are 
referred to as 3-month parameter means) and are validated according to 
the criteria specified in section 4(c). The parameter-specific 3-month 
means are then prioritized according to section 2(a) to determine a 
single 3-month site mean.
    Year refers to a calendar year.
    2. Use of Pb-PM10 Data as Surrogate Pb-TSP Data.
    (a) As stipulated in section 2.10 of Appendix C to 40 CFR part 58, 
at some mandatory Pb monitoring locations, monitoring agencies are 
required to sample for Pb as Pb-TSP, and at other mandatory Pb 
monitoring sites, monitoring agencies are permitted to monitor for Pb-
PM10 in lieu of Pb-TSP. In either situation, valid collocated 
Pb data for the other parameter may be produced. Additionally, there may 
be non-required monitoring locations that also produce valid Pb-TSP and/
or valid Pb-PM10 data. Pb-TSP data and Pb-PM10 
data are always processed separately when computing monthly and 3-month 
parameter means; monthly and 3-month parameter means are validated 
according to the criteria stated in section 4 of this appendix. Three-
month ``site'' means, which are the final valid 3-month mean from which 
a design value is identified, are determined from the one or two 
available valid 3-month parameter means according to the following 
prioritization which applies to all Pb monitoring locations.
    (i) Whenever a valid 3-month Pb-PM10 mean shows a 
violation and either is greater than a corresponding (collocated) 3-
month Pb-TSP mean or there is no corresponding valid 3-month Pb-TSP mean 
present, then that 3-month Pb-PM10 mean will be the site-
level mean for that (site's) 3-month period.
    (ii) Otherwise (i.e., there is no valid violating 3-month Pb-
PM10 that exceeds a corresponding 3-month Pb-TSP mean),
    (A) If a valid 3-month Pb-TSP mean exists, then it will be the site-
level mean for that (site's) 3-month period, or
    (B) If a valid 3-month Pb-TSP mean does not exist, then there is no 
valid 3-month site mean for that period (even if a valid non-violating 
3-month Pb-PM10 mean exists).
    (b) As noted in section 1(a) of this appendix, FRM/FEM Pb-
PM10 data will be processed at face value (i.e., at reported 
concentrations) without adjustment when computing means and making NAAQS 
comparisons.
    3. Requirements for Data Used for Comparisons With the Pb NAAQS and 
Data Reporting Considerations.
    (a) All valid FRM/FEM Pb-TSP data and all valid FRM/FEM Pb-
PM10 data submitted to EPA's Air Quality System (AQS), or 
otherwise available to EPA, meeting the requirements of part 58 of this 
chapter including appendices A, C, and E shall be used in design value 
calculations. Pb-TSP and Pb-PM10 data representing sample 
collection periods prior to January 1, 2009 (i.e., ``pre-rule'' data) 
will also be considered valid for NAAQS comparisons and related 
attainment/nonattainment determinations if the sampling and analysis 
methods that were utilized to collect that data were consistent with 
previous or newly designated FRMs or FEMs and with either the provisions 
of part 58 of this chapter including appendices A, C,

[[Page 137]]

and E that were in effect at the time of original sampling or that are 
in effect at the time of the attainment/nonattainment determination, and 
if such data are submitted to AQS prior to September 1, 2009.
    (b) Pb-TSP and Pb-PM10 measurement data are reported to 
AQS in units of micrograms per cubic meter ([micro]g/m\3\) at local 
conditions (local temperature and pressure, LC) to three decimal places; 
any additional digits to the right of the third decimal place are 
truncated. Pre-rule Pb-TSP and Pb-PM10 concentration data 
that were reported in standard conditions (standard temperature and 
standard pressure, STP) will not require a conversion to local 
conditions but rather, after truncating to three decimal places and 
processing as stated in this appendix, shall be compared ``as is'' to 
the NAAQS (i.e., the LC to STP conversion factor will be assumed to be 
one). However, if the monitoring agency has retroactively resubmitted 
Pb-TSP or Pb-PM10 pre-rule data converted from STP to LC 
based on suitable meteorological data, only the LC data will be used.
    (c) At each monitoring location (site), Pb-TSP and Pb-
PM10 data are to be processed separately when selecting daily 
data by day (as specified in section 3(d) of this appendix), when 
aggregating daily data by month (per section 6(a)), and when forming 3-
month means (per section 6(b)). However, when deriving (i.e., 
identifying) the design value for the 38-month period, 3-month means for 
the two data types may be considered together; see sections 2(a) and 
4(e) of this appendix for details.
    (d) Daily values for sites will be selected for a site on a size cut 
(Pb-TSP or Pb-PM10, i.e., ``parameter'') basis; Pb-TSP 
concentrations and Pb-PM10 concentrations shall not be 
commingled in these determinations. Site level, parameter-specific daily 
values will be selected as follows:
    (i) The starting dataset for a site-parameter shall consist of the 
measured daily concentrations recorded from the designated primary FRM/
FEM monitor for that parameter. The primary monitor for each parameter 
shall be designated in the appropriate state or local agency annual 
Monitoring Network Plan. If no primary monitor is designated, the 
Administrator will select which monitor to treat as primary. All daily 
values produced by the primary sampler are considered part of the site-
parameter data record (i.e., that site-parameter's set of daily values); 
this includes all creditable samples and all extra samples. For pre-rule 
Pb-TSP and Pb-PM10 data, valid data records present in AQS 
for the monitor with the lowest occurring Pollutant Occurrence Code 
(POC), as selected on a site-parameter-daily basis, will constitute the 
site-parameter data record. Where pre-rule Pb-TSP data (or subsequent 
non-required Pb-TSP or Pb-PM10 data) are reported in 
``composite'' form (i.e., multiple filters for a month of sampling that 
are analyzed together), the composite concentration will be used as the 
site-parameter monthly mean concentration if there are no valid daily 
Pb-TSP data reported for that month with a lower POC.
    (ii) Data for the primary monitor for each parameter shall be 
augmented as much as possible with data from collocated (same parameter) 
FRM/FEM monitors. If a valid 24-hour measurement is not produced from 
the primary monitor for a particular day (scheduled or otherwise), but a 
valid sample is generated by a collocated (same parameter) FRM/FEM 
instrument, then that collocated value shall be considered part of the 
site-parameter data record (i.e., that site-parameter's monthly set of 
daily values). If more than one valid collocated FRM/FEM value is 
available, the mean of those valid collocated values shall be used as 
the daily value. Note that this step will not be necessary for pre-rule 
data given the daily identification presumption for the primary monitor.
    (e) All daily values in the composite site-parameter record are used 
in monthly mean calculations. However, not all daily values are given 
credit towards data completeness requirements. Only ``creditable'' 
samples are given credit for data completeness. Creditable samples 
include valid samples on scheduled sampling days and valid make-up 
samples. All other types of daily values are referred to as ``extra'' 
samples. Make-up samples taken in the (first week of the) month after 
the one in which the miss/void occurred will be credited for data 
capture in the month of the miss/void but will be included in the month 
actually taken when computing monthly means. For example, if a make-up 
sample was taken in February to replace a missed sample scheduled for 
January, the make-up concentration would be included in the February 
monthly mean but the sample credited in the January data capture rate.
    4. Comparisons With the Pb NAAQS.
    (a) The Pb NAAQS is met at a monitoring site when the identified 
design value is valid and less than or equal to 0.15 micrograms per 
cubic meter ([micro]g/m\3\). A Pb design value that meets the NAAQS 
(i.e., 0.15 [micro]g/m\3\ or less), is considered valid if it 
encompasses 36 consecutive valid 3-month site means (specifically for a 
3-year calendar period and the two previous months). For sites that 
begin monitoring Pb after this rule is effective but before January 15, 
2010 (or January 15, 2011), a 2010-2012 (or 2011-2013) Pb design value 
that meets the NAAQS will be considered valid if it encompasses at least 
34 consecutive valid 3-month means (specifically encompassing only the 
3-year calendar period). See 4(c) of this appendix for the description 
of a valid 3-month mean and section 6(d) for the definition of the 
design value.

[[Page 138]]

    (b) The Pb NAAQS is violated at a monitoring site when the 
identified design value is valid and is greater than 0.15 [micro]g/m\3\, 
no matter whether determined from Pb-TSP or Pb-PM10 data. A 
Pb design value greater than 0.15 [micro]g/m\3\ is valid no matter how 
many valid 3-month means in the 3-year period it encompasses; that is, a 
violating design value is valid even if it (i.e., the highest 3-month 
mean) is the only valid 3-month mean in the 3-year timeframe. Further, a 
site does not have to monitor for three full calendar years in order to 
have a valid violating design value; a site could monitor just three 
months and still produce a valid (violating) design value.
    (c)(i) A 3-month parameter mean is considered valid (i.e., meets 
data completeness requirements) if the average of the data capture rate 
of the three constituent monthly means (i.e., the 3-month data capture 
rate) is greater than or equal to 75 percent. Monthly data capture rates 
(expressed as a percentage) are specifically calculated as the number of 
creditable samples for the month (including any make-up samples taken 
the subsequent month for missed samples in the month in question, and 
excluding any make-up samples taken in the month in question for missed 
samples in the previous month) divided by the number of scheduled 
samples for the month, the result then multiplied by 100 but not 
rounded. The 3-month data capture rate is the sum of the three 
corresponding unrounded monthly data capture rates divided by three and 
the result rounded to the nearest integer (zero decimal places). As 
noted in section 3(c), Pb-TSP and Pb-PM10 daily values are 
processed separately when calculating monthly means and data capture 
rates; a Pb-TSP value cannot be used as a make-up for a missing Pb-
PM10 value or vice versa. For purposes of assessing data 
capture, Pb-TSP and Pb-PM10 data collected before January 1, 
2009 will be treated with an assumed scheduled sampling frequency of 
every sixth day.
    (ii) A 3-month parameter mean that does not have at least 75 percent 
data capture and thus is not considered valid under 4(c)(i) shall be 
considered valid (and complete) if it passes either of the two following 
``data substitution'' tests, one such test for validating an above 
NAAQS-level (i.e., violating) 3-month Pb-TSP or Pb-PM10 mean 
(using actual ``low'' reported values from the same site at about the 
same time of the year (i.e., in the same month) looking across three or 
four years), and the second test for validating a below-NAAQS level 3-
month Pb-TSP mean (using actual ``high'' values reported for the same 
site at about the same time of the year (i.e., in the same month) 
looking across three or four years). Note that both tests are merely 
diagnostic in nature intending to confirm that there is a very high 
likelihood if not certainty that the original mean (the one with less 
than 75% data capture) reflects the true over/under NAAQS-level status 
for that 3-month period; the result of one of these data substitution 
tests (i.e., a ``test mean'', as defined in section 4(c)(ii)(A) or 
4(c)(ii)(B)) is not considered the actual 3-month parameter mean and 
shall not be used in the determination of design values. For both types 
of data substitution, substitution is permitted only if there are 
available data points from which to identify the high or low 3-year 
month-specific values, specifically if there are at least 10 data points 
total from at least two of the three (or four for November and December) 
possible year-months. Data substitution may only use data of the same 
parameter type.
    (A) The ``above NAAQS level'' test is as follows: Data substitution 
will be done in each month of the 3-month period that has less than 75 
percent data capture; monthly capture rates are temporarily rounded to 
integers (zero decimals) for this evaluation. If by substituting the 
lowest reported daily value for that month (year non-specific; e.g., for 
January) over the 38-month design value period in question for missing 
scheduled data in the deficient months (substituting only enough to meet 
the 75 percent data capture minimum), the computation yields a 
recalculated test 3-month parameter mean concentration above the level 
of the standard, then the 3-month period is deemed to have passed the 
diagnostic test and the level of the standard is deemed to have been 
exceeded in that 3-month period. As noted in section 4(c)(ii), in such a 
case, the 3-month parameter mean of the data actually reported, not the 
recalculated (``test'') result including the low values, shall be used 
to determine the design value.
    (B) The ``below NAAQS level'' test is as follows: Data substitution 
will be performed for each month of the 3-month period that has less 
than 75 percent but at least 50 percent data capture; if any month has 
less than 50% data capture then the 3-month mean can not utilize this 
substitution test. Also, incomplete 3-month Pb-PM10 means can 
not utilize this test. A 3-month Pb-TSP mean with less than 75% data 
capture shall still be considered valid (and complete) if, by 
substituting the highest reported daily value, month-specific, over the 
3-year design value period in question, for all missing scheduled data 
in the deficient months (i.e., bringing the data capture rate up to 
100%), the computation yields a recalculated 3-month parameter mean 
concentration equal or less than the level of the standard (0.15 
[micro]g/m\3\), then the 3-month mean is deemed to have passed the 
diagnostic test and the level of the standard is deemed not to have been 
exceeded in that 3-month period (for that parameter). As noted in 
section 4(c)(ii), in such a case, the 3-month parameter mean of the data 
actually reported, not the recalculated (``test'') result

[[Page 139]]

including the high values, shall be used to determine the design value.
    (d) Months that do not meet the completeness criteria stated in 
4(c)(i) or 4(c)(ii), and design values that do not meet the completeness 
criteria stated in 4(a) or 4(b), may also be considered valid (and 
complete) with the approval of, or at the initiative of, the 
Administrator, who may consider factors such as monitoring site 
closures/moves, monitoring diligence, the consistency and levels of the 
valid concentration measurements that are available, and nearby 
concentrations in determining whether to use such data.
    (e) The site-level design value for a 38-month period (three 
calendar years plus two previous months) is identified from the 
available (between one and 36) valid 3-month site means. In a situation 
where there are valid 3-month means for both parameters (Pb-TSP and Pb-
PM10), the mean originating from the reported Pb-TSP data 
will be the one deemed the site-level monthly mean and used in design 
value identifications unless the Pb-PM10 mean shows a 
violation of the NAAQS and exceeds the Pb-TSP mean; see section 2(a) for 
details. A monitoring site will have only one site-level 3-month mean 
per 3-month period; however, the set of site-level 3-month means 
considered for design value identification (i.e., one to 36 site-level 
3-month means) can be a combination of Pb-TSP and Pb-PM10 
data.
    (f) The procedures for calculating monthly means and 3-month means, 
and identifying Pb design values are given in section 6 of this 
appendix.
    5. Rounding Conventions.
    (a) Monthly means and monthly data capture rates are not rounded.
    (b) Three-month means shall be rounded to the nearest hundredth 
[micro]g/m\3\ (0.xx). Decimals 0.xx5 and greater are rounded up, and any 
decimal lower than 0.xx5 is rounded down. E.g., a 3-month mean of 
0.104925 rounds to 0.10 and a 3-month mean of .10500 rounds to 0.11. 
Three-month data capture rates, expressed as a percent, are round to 
zero decimal places.
    (c) Because a Pb design value is simply a (highest) 3-month mean and 
because the NAAQS level is stated to two decimal places, no additional 
rounding beyond what is specified for 3-month means is required before a 
design value is compared to the NAAQS.
    6. Procedures and Equations for the Pb NAAQS.
    (a)(i) A monthly mean value for Pb-TSP (or Pb-PM10) is 
determined by averaging the daily values of a calendar month using 
equation 1 of this appendix, unless the Administrator chooses to 
exercise his discretion to use the alternate approach described in 
6(a)(ii).
[GRAPHIC] [TIFF OMITTED] TR12NO08.001

Where:

Xm,y,s = the mean for month m of the year y for sites; and
nm = the number of daily values in the month (creditable plus extra 
samples); and
Xi,m,y,s = the ith value in month m for year y for site s.

    (a)(ii) The Administrator may at his discretion use the following 
alternate approach to calculating the monthly mean concentration if the 
number of extra sampling days during a month is greater than the number 
of successfully completed scheduled and make-up sample days in that 
month. In exercising his discretion, the Administrator will consider 
whether the approach specified in 6(a)(i) might in the Administrator's 
judgment result in an unrepresentative value for the monthly mean 
concentration. This provision is to protect the integrity of the monthly 
and 3-month mean concentration values in situations in which, by 
intention or otherwise, extra sampling days are concentrated in a period 
during which ambient concentrations are particularly high or low. The 
alternate approach is to average all extra and make-up samples (in the 
given month) taken after each scheduled sampling day (``Day X'') and 
before the next scheduled sampling day (e.g., ``Day X+6'', in the case 
of one-in-six sampling) with the sample taken on Day X (assuming valid 
data was obtained on the scheduled sampling day), and then averaging 
these averages to calculate the monthly mean. This approach has the 
effect of giving approximately equal weight to periods during a month 
that have equal number of days, regardless of how many samples were 
actually obtained during the periods, thus mitigating the potential for 
the monthly mean to be distorted. The first day of scheduled sampling 
typically will not fall on the first day of the calendar month, and 
there may be make-up and/or extra samples (in that same calendar month) 
preceding the first scheduled day of the month. These samples will not 
be shifted into the previous month's mean concentration, but rather will 
stay associated with their actual calendar month as follows. Any extra 
and make-up samples taken in a month before the first scheduled sampling 
day of the month will be associated with and averaged with the last 
scheduled sampling day of that same month.
    (b) Three-month parameter means are determined by averaging three 
consecutive monthly means of the same parameter using Equation 2 of this 
appendix.

[[Page 140]]

[GRAPHIC] [TIFF OMITTED] TR12NO08.002

Where:

Xm1, m2, m3; s = the 3-month parameter mean for months m1, m2, and m3 
for site s; and
nm = the number of monthly means available to be averaged (typically 3, 
sometimes 1 or 2 if one or two months have no valid daily values); and
Xm, y: z, s = The mean for month m of the year y (or z) for site s.

    (c) Three-month site means are determined from available 3-month 
parameter means according to the hierarchy established in 2(a) of this 
appendix.
    (d) The site-level Pb design value is the highest valid 3-month 
site-level mean over the most recent 38-month period (i.e., the most 
recent 3-year calendar period plus two previous months). Section 4(a) of 
this appendix explains when the identified design value is itself 
considered valid for purposes of determining that the NAAQS is met or 
violated at a site.

[73 FR 67054, Nov. 12, 2008]



PART 51_REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF 
IMPLEMENTATION PLANS--Table of Contents




Sec.

             Subpart A_Air Emissions Reporting Requirements

               General Information For Inventory Preparers

51.1 Who is responsible for actions described in this subpart?
51.5 What tools are available to help prepare and report emissions data?
51.10 How does my state report emissions that are required by the 
          NOX SIP Call?

                     Specific Reporting Requirements

51.15 What data does my state need to report to EPA?
51.20 What are the emission thresholds that separate point and nonpoint 
          sources?
51.25 What geographic area must my state's inventory cover?
51.30 When does my state report which emissions data to EPA?
51.35 How can my state equalize the emission inventory effort from year 
          to year?
51.40 In what form and format should my state report the data to EPA?
51.45 Where should my state report the data?
51.50 What definitions apply to this subpart?

Appendix A to Subpart A of Part 51--Tables
Appendix B to Subpart A of Part 51 [Reserved]

Subparts B-E [Reserved]

                    Subpart F_Procedural Requirements

51.100 Definitions.
51.101 Stipulations.
51.102 Public hearings.
51.103 Submission of plans, preliminary review of plans.
51.104 Revisions.
51.105 Approval of plans.

                       Subpart G_Control Strategy

51.110 Attainment and maintenance of national standards.
51.111 Description of control measures.
51.112 Demonstration of adequacy.
51.113 [Reserved]
51.114 Emissions data and projections.
51.115 Air quality data and projections.
51.116 Data availability.
51.117 Additional provisions for lead.
51.118 Stack height provisions.
51.119 Intermittent control systems.
51.120 Requirements for State Implementation Plan revisions relating to 
          new motor vehicles.
51.121 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of oxides of nitrogen.
51.122 Emissions reporting requirements for SIP revisions relating to 
          budgets for NOX emissions.
51.123 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of oxides of nitrogen 
          pursuant to the Clean Air Interstate Rule.
51.124 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of sulfur dioxide 
          pursuant to the Clean Air Interstate Rule.
51.125 Emissions reporting requirements for SIP revisions relating to 
          budgets for SO2 and NOX emissions.

        Subpart H_Prevention of Air Pollution Emergency Episodes

51.150 Classification of regions for episode plans.
51.151 Significant harm levels.
51.152 Contingency plans.
51.153 Reevaluation of episode plans.

[[Page 141]]

            Subpart I_Review of New Sources and Modifications

51.160 Legally enforceable procedures.
51.161 Public availability of information.
51.162 Identification of responsible agency.
51.163 Administrative procedures.
51.164 Stack height procedures.
51.165 Permit requirements.
51.166 Prevention of significant deterioration of air quality.

               Subpart J_Ambient Air Quality Surveillance

51.190 Ambient air quality monitoring requirements.

                      Subpart K_Source Survelliance

51.210 General.
51.211 Emission reports and recordkeeping.
51.212 Testing, inspection, enforcement, and complaints.
51.213 Transportation control measures.
51.214 Continuous emission monitoring.

                        Subpart L_Legal Authority

51.230 Requirements for all plans.
51.231 Identification of legal authority.
51.232 Assignment of legal authority to local agencies.

                Subpart M_Intergovernmental Consultation

                           Agency Designation

51.240 General plan requirements.
51.241 Nonattainment areas for carbon monoxide and ozone.
51.242 [Reserved]

                     Subpart N_Compliance Schedules

51.260 Legally enforceable compliance schedules.
51.261 Final compliance schedules.
51.262 Extension beyond one year.

            Subpart O_Miscellaneous Plan Content Requirements

51.280 Resources.
51.281 Copies of rules and regulations.
51.285 Public notification.
51.286 Electronic reporting.

                   Subpart P_Protection of Visibility

51.300 Purpose and applicability.
51.301 Definitions.
51.302 Implementation control strategies for reasonably attributable 
          visibility impairment.
51.303 Exemptions from control.
51.304 Identification of integral vistas.
51.305 Monitoring for reasonably attributable visibility impairment.
51.306 Long-term strategy requirements for reasonably attributable 
          visibility impairment.
51.307 New source review.
51.308 Regional haze program requirements.
51.309 Requirements related to the Grand Canyon Visibility Transport 
          Commission.

                            Subpart Q_Reports

                       Air Quality Data Reporting

51.320 Annual air quality data report.

               Source Emissions and State Action Reporting

51.321 Annual source emissions and State action report.
51.322 Sources subject to emissions reporting.
51.323 Reportable emissions data and information.
51.324 Progress in plan enforcement.
51.326 Reportable revisions.
51.327 Enforcement orders and other State actions.
51.328 [Reserved]

                          Subpart R_Extensions

51.341 Request for 18-month extension.

          Subpart S_Inspection/Maintenance Program Requirements

51.350 Applicability.
51.351 Enhanced I/M performance standard.
51.352 Basic I/M performance standard.
51.353 Network type and program evaluation.
51.354 Adequate tools and resources.
51.355 Test frequency and convenience.
51.356 Vehicle coverage.
51.357 Test procedures and standards.
51.358 Test equipment.
51.359 Quality control.
51.360 Waivers and compliance via diagnostic inspection.
51.361 Motorist compliance enforcement.
51.362 Motorist compliance enforcement program oversight.
51.363 Quality assurance.
51.364 Enforcement against contractors, stations and inspectors.
51.365 Data collection.
51.366 Data analysis and reporting.
51.367 Inspector training and licensing or certification.
51.368 Public information and consumer protection.
51.369 Improving repair effectiveness.
51.370 Compliance with recall notices.
51.371 On-road testing.
51.372 State Implementation Plan submissions.

[[Page 142]]

51.373 Implementation deadlines.

Appendix A to Subpart S--Calibrations, Adjustments and Quality Control
Appendix B to Subpart S--Test Procedures
Appendix C to Subpart S--Steady-State Short Test Standards
Appendix D to Subpart S--Steady-State Short Test Equipment
Appendix E to Subpart S--Transient Test Driving Cycle

    Subpart T_Conformity to State or Federal Implementation Plans of 
   Transportation Plans, Programs, and Projects Developed, Funded or 
       Approved Under Title 23 U.S.C. or the Federal Transit Laws

51.390 Implementation plan revision.

                  Subpart U_Economic Incentive Programs

51.490 Applicability.
51.491 Definitions.
51.492 State program election and submittal.
51.493 State program requirements.
51.494 Use of program revenues.

Subpart W_Determining Conformity of General Federal Actions to State or 
                      Federal Implementation Plans

51.850 Prohibition.
51.851 State Implementation Plan (SIP) revision.
51.852 Definitions.
51.853 Applicability.
51.854 Conformity analysis.
51.855 Reporting requirements.
51.856 Public participation.
51.857 Frequency of conformity determinations.
51.858 Criteria for determining conformity of general Federal actions.
51.859 Procedures for conformity determinations of general Federal 
          actions.
51.860 Mitigation of air quality impacts.

Subpart X_Provisions for Implementation of 8-hour Ozone National Ambient 
                          Air Quality Standard

51.900 Definitions.
51.901 Applicability of part 51.
51.902 Which classification and area planning provisions of the CAA 
          shall apply to areas designated nonattainment for the 8-hour 
          NAAQS?
51.903 How do the classification and attainment date provisions in 
          section 181 of subpart 2 of the CAA apply to areas subject to 
          Sec. 51.902(a)?
51.904 How do the classification and attainment date provisions in 
          section 172(a) of subpart 1 of the CAA apply to areas subject 
          to Sec. 51.902(b)?
51.905 How do areas transition from the 1-hour NAAQS to the 8-hour NAAQS 
          and what are the anti-backsliding provisions?
51.906 Redesignation to nonattainment following initial designations for 
          the 8-hour NAAQS.
51.907 For an area that fails to attain the 8-hour NAAQS by its 
          attainment date, how does EPA interpret sections 
          172(a)(2)(C)(ii) and 181(a)(5)(B) of the CAA?
51.908 What modeling and attainment demonstration requirements apply for 
          purposes of the 8-hour ozone NAAQS?
51.909 [Reserved]
51.910 What requirements for reasonable further progress (RFP) under 
          sections 172(c)(2) and 182 apply for areas designated 
          nonattainment for the 8-hour ozone NAAQS?
51.911 [Reserved]
51.912 What requirements apply for reasonably available control 
          technology (RACT) and reasonably available control measures 
          (RACM) under the 8-hour NAAQS?
51.913 How do the section 182(f) NOX exemption provisions 
          apply for the 8-hour NAAQS?
51.914 What new source review requirements apply for 8-hour ozone 
          nonattainment areas?
51.915 What emissions inventory requirements apply under the 8-hour 
          NAAQS?
51.916 What are the requirements for an Ozone Transport Region under the 
          8-hour NAAQS?
51.917 What is the effective date of designation for the Las Vegas, NV, 
          8-hour ozone nonattainment area?
51.918 Can any SIP planning requirements be suspended in 8-hour ozone 
          nonattainment areas that have air quality data that meets the 
          NAAQS?

                    Subpart Y_Mitigation Requirements

51.930 Mitigation of Exceptional Events.

 Subpart Z_Provisions for Implementation of PM2.5 National Ambient Air 
                            Quality Standards

51.1000 Definitions.
51.1001 Applicability of part 51.
51.1002 Submittal of State implementation plan.
51.1003 [Reserved]
51.1004 Attainment dates.
51.1005 One-year extensions of the attainment date.
51.1006 Redesignation to nonattainment following initial designations 
          for the PM2.5 NAAQS.
51.1007 Attainment demonstration and modeling requirements.

[[Page 143]]

51.1008 Emission inventory requirements for the PM2.5 NAAQS.
51.1009 Reasonable further progress (RFP) requirements.
51.1010 Requirements for reasonably available control technology (RACT) 
          and reasonably available control measures (RACM).
51.1011 Requirements for mid-course review.
51.1012. Requirements for contingency measures.

Appendixes A-K to Part 51 [Reserved]
Appendix L to Part 51--Example Regulations for Prevention of Air 
          Pollution Emergency Episodes
Appendix M to Part 51--Recommended Test Methods for State Implementation 
          Plans
Appendixes N-O to Part 51 [Reserved]
Appendix P to Part 51--Minimum Emission Monitoring Requirements
Appendixes Q-R to Part 51 [Reserved]
Appendix S to Part 51--Emission Offset Interpretative Ruling
Appendixes T-U to Part 51 [Reserved]
Appendix V to Part 51--Criteria for Determining the Completeness of Plan 
          Submissions
Appendix W to Part 51--Guideline on Air Quality Models
Appendix X to Part 51--Examples of Economic Incentive Programs
Appendix Y to Part 51--Guidelines for BART Determinations Under the 
          Regional Haze Rule

    Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.

    Source: 36 FR 22398, Nov. 25, 1971, unless otherwise noted.



             Subpart A_Air Emissions Reporting Requirements

    Source: 73 FR 76552, Dec. 17, 2008, unless otherwise noted.

               General Information for Inventory Preparers



Sec. 51.1  Who is responsible for actions described in this subpart?

    States must inventory emission sources located on nontribal lands 
and report this information to EPA.



Sec. 51.5  What tools are available to help prepare and report
emissions data?

    (a) We urge your state to use estimation procedures described in 
documents from the Emission Inventory Improvement Program (EIIP), 
available at the following Internet address: http://www.epa.gov/ttn/
chief/eiip. These procedures are standardized and ranked according to 
relative uncertainty for each emission estimating technique. Using this 
guidance will enable others to use your state's data and evaluate its 
quality and consistency with other data.
    (b) Where current EIIP guidance materials have been supplanted by 
state-of-the-art emission estimation approaches or are not applicable to 
sources or source categories, states are urged to use applicable, state-
of-the-art techniques for estimating emissions.



Sec. 51.10  How does my state report emissions that are required by
the NOX SIP Call?

    The District of Columbia and states that are subject to the 
NOX SIP Call Sec. 51.121) are subject to the emissions 
reporting provisions of Sec. 51.122. This subpart A incorporates the 
pollutants, source, time periods, and required data elements for these 
reporting requirements.

                     Specific Reporting Requirements



Sec. 51.15  What data does my state need to report to EPA?

    (a) Pollutants. Report actual emissions of the following (see Sec. 
51.50 for precise definitions as required):
    (1) Required pollutants for triennial reports of annual (12-month) 
emissions for all sources and every-year reports of annual emissions 
from Type A sources:
    (i) Sulfur dioxide (SO2).
    (ii) Volatile organic compounds (VOC).
    (iii) Nitrogen oxides (NOX).
    (iv) Carbon monoxide (CO).
    (v) Lead and lead compounds.
    (vi) Primary PM2.5 . As applicable, also report 
filterable and condensable components.
    (vii) Primary PM10 . As applicable, also report 
filterable and condensable components.
    (viii) Ammonia (NH3 ).
    (2) Required pollutants for all reports of ozone season (5 months) 
emissions: NOX.
    (3) Required pollutants for triennial reports of summer day 
emissions:
    (i) NOX.

[[Page 144]]

    (ii) VOC.
    (4) Required pollutants for every-year reports of summer day 
emissions: NOX.
    (5) A state may, at its option, include estimates of emissions for 
additional pollutants (such as other pollutants listed in paragraph 
(a)(1) of this section or hazardous air pollutants) in its emission 
inventory reports.
    (b) Sources. Emissions should be reported from the following sources 
in all parts of the state, excluding sources located on tribal lands:
    (1) Point.
    (2) Nonpoint.
    (3) Onroad mobile.
    (4) Nonroad mobile.
    (c) Supporting Information. You must report the data elements in 
Tables 2a through 2c in Appendix A of this subpart. We may ask you for 
other data on a voluntary basis to meet special purposes.
    (d) Confidential Data. We do not consider the data in Tables 2a 
through 2c in Appendix A of this subpart confidential, but some states 
limit release of this type of data. Any data that you submit to EPA 
under this subpart will be considered in the public domain and cannot be 
treated as confidential. If Federal and state requirements are 
inconsistent, consult your EPA Regional Office for a final 
reconciliation.
    (e) Option to Submit Inputs to Emission Inventory Estimation Models 
in Lieu of Emission Estimates. For a given inventory year, EPA may allow 
states to submit comprehensive input values for models capable of 
estimating emissions from a certain source type on a national scale, in 
lieu of submitting the emission estimates otherwise required by this 
subpart.



Sec. 51.20  What are the emission thresholds that separate point and
nonpoint sources?

    (a) All anthropogenic stationary sources must be included in your 
inventory as either point or nonpoint sources.
    (b) Sources that meet the definition of point source in this subpart 
must be reported as point sources. All pollutants specified in Sec. 
51.15(a) must be reported for point sources, not just the pollutant(s) 
that qualify the source as a point source. The reporting of wildland and 
agricultural fires is encouraged but not required.
    (c) If your state has lower emission reporting thresholds for point 
sources than paragraph (b) of this section, then you may use these in 
reporting your emissions to EPA.
    (d) All stationary sources that are not reported as point sources 
must be reported as nonpoint sources. Episodic wind-generated 
particulate matter (PM) emissions from sources that are not major 
sources may be excluded, for example dust lifted by high winds from 
natural or tilled soil. In addition, if not reported as point sources, 
wildland and agricultural fires must be reported as nonpoint sources. 
Emissions of nonpoint sources may be aggregated to the county level, but 
must be separated and identified by source classification code (SCC). 
Nonpoint source categories or emission events reasonably estimated by 
the state to represent a de minimis percentage of total county and state 
emissions of a given pollutant may be omitted.



Sec. 51.25  What geographic area must my state's inventory cover?

    Because of the regional nature of these pollutants, your state's 
inventory must be statewide, regardless of any area's attainment status.



Sec. 51.30  When does my state report which emissions data to EPA?

    All states are required to report two basic types of emission 
inventories to EPA: Every-year Cycle Inventory; and Three-year Cycle 
Inventory. The sources and pollutants to be reported vary among states.
    (a) Every-year cycle. See Tables 2a, 2b, and 2c of Appendix A of 
this subpart for the specific data elements to report every year.
    (1) All states are required to report every year the annual (12-
month) emissions of all pollutants listed in Sec. 51.15(a)(1) from Type 
A (large) point sources, as defined in Table 1 of Appendix A of this 
subpart. The first every-year cycle inventory will be for the 2009 
inventory year and must be submitted to EPA within 12 months, i.e., by 
December 31, 2010.
    (2) States subject to the emission reporting requirements of Sec. 
51.122 (the

[[Page 145]]

NOX SIP Call) are required to report every year the ozone 
season emissions of NOX and summer day emissions of 
NOX from any point, nonpoint, onroad mobile, or nonroad 
mobile source for which the state specified control measures in its SIP 
submission under Sec. 51.121(g). This requirement begins with the 
inventory year prior to the year in which compliance with the 
NOX SIP Call requirements is first required.
    (3) In inventory years that fall under the 3-year cycle 
requirements, the reporting required by the 3-year cycle satisfies the 
every-year reporting requirements of paragraph (a).
    (b) Three-year cycle. See Tables 2a, 2b and 2c to Appendix A of 
subpart A for the specific data elements that must be reported 
triennially.
    (1) All states are required to report for every third inventory year 
the annual (12-month) emissions of all pollutants listed in Sec. 
51.15(a)(1) from all point sources, nonpoint sources, onroad mobile 
sources, and nonroad mobile sources. The first 3-year cycle inventory 
will be for the 2011 inventory and must be submitted to us within 12 
months, i.e., by December 31, 2012. Subsequent 3-year cycle (2011, 2014, 
etc.) inventories will be due 12 months after the end of the inventory 
year, i.e., by December 31 of the following year.
    (2) States subject to Sec. 51.122 must report ozone season 
emissions and summer day emissions of NOX from all point 
sources, nonpoint sources, onroad mobile sources, and nonroad mobile 
sources. The first 3-year cycle inventory will be for the 2008 inventory 
year and must be submitted to EPA within 12 months, i.e., by December 
31, 2009. Subsequent 3-year cycle inventories will be due as specified 
under paragraph (b)(1) of this section.
    (3) Any state with an area for which EPA has made an 8-hour ozone 
nonattainment designation finding (regardless of whether that finding 
has reached its effective date) must report summer day emissions of VOC 
and NOX from all point sources, nonpoint sources, onroad 
mobile sources, and nonroad mobile sources. Summer day emissions of 
NOX and VOC for sources in attainment counties that are 
covered by the nonattainment area modeling domain used to demonstrate 
reasonable further progress (RFP) must be included. The first 3-year 
cycle inventory will be for the 2011 inventory year and must be 
submitted to EPA within 12 months, i.e., by December 31, 2012. 
Subsequent three-year cycle inventories will be due as specified under 
paragraph (b)(1) of this section.
    (4) States with CO nonattainment areas and states with CO attainment 
areas subject to maintenance plans must report winter work weekday 
emissions of CO with their 3-year cycle inventories.



Sec. 51.35  How can my state equalize the emission inventory effort
from year to year?

    (a) Compiling a 3-year cycle inventory means more effort every 3 
years. As an option, your state may ease this workload spike by using 
the following approach:
    (1) Each year, collect and report data for all Type A (large) point 
sources (this is required for all Type A point sources).
    (2) Each year, collect data for one-third of your sources that are 
not Type A point sources. Collect data for a different third of these 
sources each year so that data has been collected for all of the sources 
that are not Type A point sources by the end of each 3-year cycle. You 
must save 3 years of data and then report all emissions from the sources 
that are not Type A point sources on the 3-year cycle due date.
    (3) Each year, collect data for one-third of the nonpoint, nonroad 
mobile, and onroad mobile sources. You must save 3 years of data for 
each such source and then report all of these data on the 3-year cycle 
due date.
    (b) For the sources described in paragraph (a) of this section, your 
state will have data from 3 successive years at any given time, rather 
than from the single year in which it is compiled.
    (c) If your state chooses the method of inventorying one-third of 
your sources that are not Type A point sources and 3-year cycle 
nonpoint, nonroad mobile, and onroad mobile sources each year, your 
state must compile each year of the 3-year period identically. For 
example, if a process has not changed for a source category or 
individual plant, your state must

[[Page 146]]

use the same emission factors to calculate emissions for each year of 
the 3-year period. If your state has revised emission factors during the 
3 years for a process that has not changed, you must resubmit previous 
years' data using the revised factor. If your state uses models to 
estimate emissions, you must make sure that the model is the same for 
all 3 years.
    (d) If your state needs a new reference year emission inventory for 
a selected pollutant, your state cannot use these optional reporting 
frequencies for the new reference year.
    (e) If your state is a NOX SIP Call state, you cannot use 
these optional reporting frequencies for NOX SIP Call 
reporting.



Sec. 51.40  In what form and format should my state report the data to EPA?

    (a) You must report your emission inventory data to us in electronic 
form.
    (b) We support specific electronic data reporting formats, and you 
are required to report your data in a format consistent with these. The 
term format encompasses the definition of one or more specific data 
fields for each of the data elements listed in Tables 2a, 2b, and 2c in 
Appendix A of this subpart; allowed code values for categorical data 
fields; transmittal information; and data table relational structure. 
Because electronic reporting technology changes continually, contact the 
EPA Emission Inventory and Analysis Group (EIAG) for the latest specific 
formats. You can find information on the current formats at the 
following Internet address: http://www.epa.gov/ttn/chief/nif/index.html. 
You may also call the air emissions contact in your EPA Regional Office 
or our Info CHIEF help desk at (919) 541-1000 or send e-mail to 
info.chief@epa.gov.



Sec. 51.45  Where should my state report the data?

    (a) Your state submits or reports data by providing it directly to 
EPA.
    (b) The latest information on data reporting procedures is available 
at the following Internet address: http://www.epa.gov/ttn/chief. You may 
also call our Info CHIEF help desk at (919) 541-1000 or e-mail to 
info.chief@epa.gov.



Sec. 51.50  What definitions apply to this subpart?

    Activity throughput means a measurable factor or parameter that 
relates directly or indirectly to the emissions of an air pollution 
source during the period for which emissions are reported. Depending on 
the type of source category, activity information may refer to the 
amount of fuel combusted, raw material processed, product manufactured, 
or material handled or processed. It may also refer to population, 
employment, or number of units. Activity throughput is typically the 
value that is multiplied against an emission factor to generate an 
emissions estimate.
    Annual emissions means actual emissions for a plant, point, or 
process that are measured or calculated to represent a calendar year.
    Ash content means inert residual portion of a fuel.
    Contact name means the complete name of the lead contact person for 
the organization transmitting the data set, including first name, middle 
name or initial, and surname.
    Contact phone number means the phone number for the contact name.
    Control device type means the name of the type of control device 
(e.g., wet scrubber, flaring, or process change).
    Day/wk in operations means days per week that the emitting process 
operates, averaged over the inventory period.
    Design capacity means a measure of the size of a point source, based 
on the reported maximum continuous throughput or output capacity of the 
unit. For a boiler, design capacity is based on the reported maximum 
continuous steam flow, usually in units of million BTU per hour.
    Emission factor means the ratio relating emissions of a specific 
pollutant to an activity or material throughput level.
    Emission release point type means the code for physical 
configuration of the release point.
    Emission type means the code describing temporal designation of 
emissions

[[Page 147]]

reported, i.e., Entire Period, Average Weekday, etc.
    Exit gas flow rate means the numeric value of the flow rate of a 
stack gas.
    Exit gas temperature means the numeric value of the temperature of 
an exit gas stream.
    Exit gas velocity means the numeric value of the velocity of an exit 
gas stream.
    Facility ID codes means the unique codes for a plant or facility 
treated as a point source, containing one or more pollutant-emitting 
units. The EPA's reporting format for a given inventory year may require 
several facility ID codes to ensure proper matching between databases, 
e.g., the state's own current and most recent facility ID codes, the 
EPA-assigned facility ID codes, and the ORIS (Department of Energy) ID 
code if applicable.
    Fall throughput (percent) means the part of the throughput or 
activity attributable to the three fall months (September, October, 
November). This expresses part of the annual activity information based 
on four seasons--typically spring, summer, fall, and winter. It is a 
percentage of the annual activity (e.g., out of 600 units produced each 
year, 150 units are produced in the fall which is 25 percent of the 
annual activity).
    FIPS Code. Federal Information Placement System (FIPS) means the 
system of unique numeric codes the government developed to identify 
states, counties and parishes for the entire United States, Puerto Rico, 
and Guam.
    Heat content means the amount of thermal heat energy in a solid, 
liquid, or gaseous fuel, averaged over the period for which emissions 
are reported. Fuel heat content is typically expressed in units of Btu/
lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
    Hr/day in operations means the hours per day that the emitting 
process operates averaged over the inventory period.
    Inventory end date means the last day of the inventory period.
    Inventory start date means the first day of the inventory period.
    Inventory year means the year for which emissions estimates are 
calculated.
    Lead (Pb) means lead as defined in 40 CFR 50.12. Lead should be 
reported as elemental lead and its compounds.
    NAICS means North American Industry Classification System code. The 
NAICS codes are U.S. Department of Commerce's codes for businesses by 
products or services and have replaced Standard Industrial 
Classification codes.
    Maximum nameplate capacity means a measure of the size of a 
generator which is put on the unit's nameplate by the manufacturer. The 
data element is reported in megawatts or kilowatts.
    Method accuracy description (MAD) codes means a set of six codes 
used to define the accuracy of latitude/longitude data for point 
sources. The six codes and their definitions are:
    (1) Coordinate Data Source Code: The code that represents the party 
responsible for providing the latitude/longitude.
    (2) Horizontal Collection Method Code: Method used to determine the 
latitude/longitude coordinates for a point on the earth.
    (3) Horizontal Accuracy Measure: The measure of accuracy (in meters) 
of the latitude/longitude coordinates.
    (4) Horizontal Reference Datum Code: Code that represents the 
reference datum used to determine the latitude/longitude coordinates.
    (5) Reference Point Code: The code that represents the place for 
which geographic coordinates were established. Code value should be 106 
(e.g., point where substance is released).
    (6) Source Map Scale Number: The number that represents the 
proportional distance on the ground for one unit of measure on the map 
or photo.
    Mobile source means a motor vehicle, nonroad engine or nonroad 
vehicle, where:
    (1) A motor vehicle is any self-propelled vehicle used to carry 
people or property on a street or highway;
    (2) A nonroad engine is an internal combustion engine (including 
fuel system) that is not used in a motor vehicle or a vehicle used 
solely for competition, or that is not affected by sections 111 or 202 
of the CAA; and
    (3) A nonroad vehicle is a vehicle that is run by a nonroad engine 
and that is

[[Page 148]]

not a motor vehicle or a vehicle used solely for competition.
    Nitrogen oxides (NOX) means nitrogen oxides 
(NOX) as defined in 40 CFR 60.2 as all oxides of nitrogen 
except N2O. Nitrogen oxides should be reported on an 
equivalent molecular weight basis as nitrogen dioxide (NO2).
    Nonpoint sources. Nonpoint sources collectively represent individual 
sources that have not been inventoried as specific point or mobile 
sources. These individual sources treated collectively as nonpoint 
sources are typically too small, numerous, or difficult to inventory 
using the methods for the other classes of sources.
    Ozone season means the period from May 1 through September 30 of a 
year.
    Particulate Matter (PM). Particulate matter is a criteria air 
pollutant. For the purpose of this subpart, the following definitions 
apply:
    (1) Filterable PM2.5 or Filterable PM10: 
Particles that are directly emitted by a source as a solid or liquid at 
stack or release conditions and captured on the filter of a stack test 
train. Filterable PM2.5 is particulate matter with an 
aerodynamic diameter equal to or less than 2.5 micrometers. Filterable 
PM10 is particulate matter with an aerodynamic diameter equal 
to or less than 10 micrometers.
    (2) Condensable PM: Material that is vapor phase at stack 
conditions, but which condenses and/or reacts upon cooling and dilution 
in the ambient air to form solid or liquid PM immediately after 
discharge from the stack. Note that all condensable PM, if present from 
a source, is typically in the PM2.5 size fraction, and 
therefore all of it is a component of both primary PM2.5 and 
primary PM10.
    (3) Primary PM2.5: The sum of filterable PM2.5 and 
condensable PM.
    (4) Primary PM10: The sum of filterable PM10 and 
condensable PM.
    (5) Secondary PM: Particles that form or grow in mass through 
chemical reactions in the ambient air well after dilution and 
condensation have occurred. Secondary PM is usually formed at some 
distance downwind from the source. Secondary PM should not be reported 
in the emission inventory and is not covered by this subpart.
    Physical address means the street address of a facility. This is the 
address of the location where the emissions occur; not, for example, the 
corporate headquarters.
    Point source means large, stationary (nonmobile), identifiable 
sources of emissions that release pollutants into the atmosphere. A 
point source is a facility that is a major source under 40 CFR part 70 
for the pollutants for which reporting is required, except for the 
emissions of hazardous air pollutants, which are not considered in 
determining whether a source is a point source under this subpart. The 
minimum point source reporting thresholds in tons per year of pollutant 
are as follows, as measured in potential to emit:

----------------------------------------------------------------------------------------------------------------
                                                                          Three-year cycle
          Pollutant               Annual cycle    --------------------------------------------------------------
                                (Type A sources)   Type B sources \1\               NAA sources \2\
----------------------------------------------------------------------------------------------------------------
(1) SOX......................         [gteqt]2500          [gteqt]100  [gteqt]100.
(2) VOC......................          [gteqt]250          [gteqt]100  O3 (moderate) [gteqt] 100.
(3) VOC......................        O3 (serious)
                                      [gteqt] 50.
(4) VOC......................         O3 (severe)
                                      [gteqt] 25.
(5) VOC......................        O3 (extreme)
                                      [gteqt] 10.
(6) NOX......................        [gteqt] 2500         [gteqt] 100  [gteqt] 100.
(7) CO.......................        [gteqt] 2500         [gteqt]1000  O3 (all areas) [gteqt] 100.
(8) CO.......................      CO (all areas)
                                     [gteqt] 100.
(9) Pb.......................           [gteqt] 5          [gteqt] 5.
(10) PM10....................         [gteqt] 250         [gteqt] 100  PM10 (moderate) [gteqt] 100.
(11) PM10....................      PM10 (serious)
                                      [gteqt] 70.
(12) PM2.5...................         [gteqt] 250         [gteqt] 100  [gteqt] 100.
(13) NH3.....................         [gteqt] 250         [gteqt] 100  [gteqt] 100.
----------------------------------------------------------------------------------------------------------------
\1\ Type A sources are a subset of the Type B sources and are the larger emitting sources by pollutant.
\2\ NAA = Nonattainment Area. Special point source reporting thresholds apply for certain pollutants by type of
  nonattainment area. The pollutants by nonattainment area are: Ozone: VOC, NOX, CO; CO: CO; PM10: PM10.


[[Page 149]]

    Pollutant code means a unique code for each reported pollutant 
assigned by the reporting format specified by EPA for each inventory 
year.
    Primary capture and control efficiencies means two values indicating 
the emissions capture efficiency and the emission reduction efficiency 
of a primary control device. Capture and control efficiencies are 
usually expressed as a percentage.
    Process ID code means a unique code for the process generating the 
emissions, typically a description of a process.
    Roadway class means a classification system developed by the Federal 
Highway Administration that defines all public roadways as to type based 
on land use and physical characteristics of the roadway.
    Rule effectiveness (RE) means a rating of how well a regulatory 
program achieves all possible emissions reductions. This rating reflects 
the assumption that controls typically are not 100 percent effective 
because of equipment downtime, upsets, decreases in control 
efficiencies, and other deficiencies in emission estimates. Rule 
effectiveness adjusts the control efficiency from what could be realized 
under ideal conditions to what is actually emitted in practice due to 
less than ideal conditions.
    Rule penetration means the percentage of a nonpoint source category 
covered by an applicable regulation.
    SCC means source classification code, a process-level code that 
describes the equipment and/or operation which is emitting pollutants.
    Site name means the name of the facility.
    Spring throughput (percent) means part of the throughput or activity 
attributable to the three Spring months (March, April, May). See also 
the definition of Fall throughput.
    Stack diameter means the inner physical diameter of a stack.
    Stack height means physical height of a stack above the surrounding 
terrain.
    Stack ID code means a unique code for the point where emissions from 
one or more processes release into the atmosphere.
    Sulfur content means the sulfur content of a fuel, usually expressed 
as percent by weight.
    Summer day emissions means an average day's emissions for a typical 
summer work weekday. The state will select the particular month(s) in 
summer and the day(s) in the work week to be represented. The selection 
of conditions should be coordinated with the conditions assumed in the 
development of reasonable further progress (RFP) plans, rate of progress 
plans and demonstrations, and/or emissions budgets for transportation 
conformity, to allow comparability of daily emission estimates.
    Summer throughput (percent) means the part of throughput or activity 
attributable to the three Summer months (June, July, August). See also 
the definition of Fall throughput.
    Total capture and control efficiency (percent) means the net 
emission reduction efficiency of all emissions collection devices.
    Type A source means large point sources with actual annual emissions 
greater than or equal to any of the emission thresholds listed in Table 
1 of Appendix A of this subpart for Type A sources. If a source is a 
Type A source for any pollutant listed in Table 1, then the emissions 
for all Table 1 pollutants must be reported for that source.
    Unit ID code means a unique code for the unit of generation of 
emissions, typically a physical piece of or a closely related set of 
equipment. The EPA's reporting format for a given inventory year may 
require multiple unit ID codes to ensure proper matching between 
databases, e.g., the state's own current and most recent unit ID codes, 
the EPA-assigned unit ID codes if any, and the ORIS (Department of 
Energy) ID code if applicable.
    VMT by SCC means vehicle miles traveled disaggregated to the SCC 
level, i.e., reflecting combinations of vehicle type and roadway class. 
Vehicle miles traveled expresses vehicle activity and is used with 
emission factors. The emission factors are usually expressed in terms of 
grams per mile of travel. Because VMT does not correlate directly to 
emissions that occur while the vehicle is not moving, nonmoving 
emissions are incorporated into the

[[Page 150]]

emission factors in EPA's MOBILE Model.
    VOC means volatile organic compounds. The EPA's regulatory 
definition of VOC is in 40 CFR 51.100.
    Winter throughput (percent) means the part of throughput or activity 
attributable to the three winter months (January, February, December of 
the same year, e.g., winter 2005 is composed of January 2005, February 
2005, and December 2005). See also the definition of Fall throughput.
    Wk/yr in operation means weeks per year that the emitting process 
operates.
    Work weekday means any day of the week except Saturday or Sunday.
    X stack coordinate (longitude) means an object's east-west 
geographical coordinate.
    Y stack coordinate (latitude) means an object's north-south 
geographical coordinate.



             Sec. Appendix A to Subpart A of Part 51--Tables

  Table 1 to Appendix A of Subpart A--Emission Thresholds by Pollutant
  (tpy\1\) for Treatment of Point Sources as Type A Under 40 CFR 51.30.
------------------------------------------------------------------------
                                               Emissions threshold for
                 Pollutant                         Type A treatment
------------------------------------------------------------------------
(1) SO2....................................  =2500.
(2) VOC....................................  =250.
(3) NOX....................................  =2500.
(4) CO.....................................  =2500.
(5) Pb.....................................  Does not determine Type A
                                              status.
(6) PM10...................................  =250.
(7) PM2.5..................................  =250.
(8) NH3\2\.................................  =250.
------------------------------------------------------------------------
\1\ tpy = Tons per year of actual emissions.
\2\ Ammonia threshold applies only in areas where ammonia emissions are
  a factor in determining whether a source is a major source, i.e.,
  where ammonia is considered a significant precursor of PM2.5.


   Table 2a to Appendix A of Subpart A--Data Elements For Reporting on
      Emissions From Point Sources, Where Required by 40 CFR 51.30
------------------------------------------------------------------------
                                           Every-year       Three-year
             Data elements                 reporting        reporting
------------------------------------------------------------------------
(1) Inventory year....................         [check]          [check]
(2) Inventory start date..............         [check]          [check]
(3) Inventory end date................         [check]          [check]
(4) Contact name......................         [check]          [check]
(5) Contact phone number..............         [check]          [check]
(6) FIPS code.........................         [check]          [check]
(7) Facility ID codes.................         [check]          [check]
(8) Unit ID code......................         [check]          [check]
(9) Process ID code...................         [check]          [check]
(10) Stack ID code....................         [check]          [check]
(11) Site name........................         [check]          [check]
(12) Physical address.................         [check]          [check]
(13) SCC..............................         [check]          [check]
(14) Heat content (fuel) (annual               [check]          [check]
 average).............................
(15) Heat content (fuel) (ozone                [check]          [check]
 season, if applicable)...............
(16) Ash content (fuel) (annual                [check]          [check]
 average).............................
(17) Sulfur content (fuel) (annual             [check]          [check]
 average).............................
(18) Pollutant code...................         [check]          [check]
(19) Activity/throughput (for each             [check]          [check]
 period reported).....................
(20) Summer day emissions (if                  [check]          [check]
 applicable)..........................
(21) Ozone season emissions (if                [check]          [check]
 applicable)..........................
(22) Annual emissions.................         [check]          [check]
(23) Emission factor..................         [check]          [check]
(24) Winter throughput (percent)......         [check]          [check]
(25) Spring throughput (percent)......         [check]          [check]
(26) Summer throughput (percent)......         [check]          [check]
(27) Fall throughput (percent)........         [check]          [check]
(28) Hr/day in operation..............         [check]          [check]
(29) Day/wk in operation..............         [check]          [check]
(30) Wk/yr in operation...............         [check]          [check]
(31) X stack coordinate (longitude)...  ...............         [check]
(32) Y stack coordinate (latitude)....  ...............         [check]

[[Page 151]]

 
(33) Method accuracy description (MAD)  ...............         [check]
 codes................................
(34) Stack height.....................  ...............         [check]
(35) Stack diameter...................  ...............         [check]
(36) Exit gas temperature.............  ...............         [check]
(37) Exit gas velocity................  ...............         [check]
(38) Exit gas flow rate...............  ...............         [check]
(39) NAICS at the Facility level......  ...............         [check]
(40) Design capacity (including boiler  ...............         [check]
 capacity if applicable)..............
(41) Maximum generator nameplate        ...............         [check]
 Capacity.............................
(42) Primary capture and control        ...............         [check]
 efficiencies (percent)...............
(43) Total capture and control          ...............         [check]
 efficiency (percent).................
(44) Control device type..............  ...............         [check]
(45) Emission type....................  ...............         [check]
(46) Emission release point type......  ...............         [check]
(47) Rule effectiveness (percent).....  ...............         [check]
(48) Winter work weekday emissions of   ...............         [check]
 CO (if applicable)...................
------------------------------------------------------------------------


   Table 2b to Appendix A of Subpart A--Data Elements For Reporting on
    Emissions from Nonpoint Sources and Nonroad Mobile Sources, Where
                        Required by 40 CFR 51.30
------------------------------------------------------------------------
                                           Every-year       Three-year
             Data elements                 reporting        reporting
------------------------------------------------------------------------
(1) Inventory year....................         [check]          [check]
 (2) Inventory start date.............         [check]          [check]
(3) Inventory end date................         [check]          [check]
 (4) Contact name.....................         [check]          [check]
 (5) Contact phone number.............         [check]          [check]
 (6) FIPS code........................         [check]          [check]
 (7) SCC..............................         [check]          [check]
 (8) Emission factor..................         [check]          [check]
 (9) Activity/throughput level (for            [check]          [check]
 each period reported)................
 (10) Total capture/control efficiency         [check]          [check]
 (percent)............................
 (11) Rule effectiveness (percent)....         [check]          [check]
 (12) Rule penetration (percent)......         [check]          [check]
 (13) Pollutant code..................         [check]          [check]
 (14) Ozone season emissions (if               [check]          [check]
 applicable)..........................
 (15) Summer day emissions (if                 [check]          [check]
 applicable)..........................
 (16) Annual emissions................         [check]          [check]
 (17) Winter throughput (percent).....         [check]          [check]
 (18) Spring throughput (percent).....         [check]          [check]
 (19) Summer throughput (percent).....         [check]          [check]
 (20) Fall throughput (percent).......         [check]          [check]
 (21) Hrs/day in operation............         [check]          [check]
 (22) Days/wk in operation............         [check]          [check]
 (23) Wks/yr in operation.............         [check]          [check]
(24) Winter work weekday emissions of   ...............         [check]
 CO (if applicable)...................
------------------------------------------------------------------------


   Table 2c to Appendix A of Subpart A--Data Elements For Reporting on
  Emissions from Onroad Mobile Sources, Where Required by 40 CFR 51.30
------------------------------------------------------------------------
                                           Every-year       Three-year
             Data elements                 reporting        reporting
------------------------------------------------------------------------
1. Inventory year.....................         [check]          [check]
2. Inventory start date...............         [check]          [check]
3. Inventory end date.................         [check]          [check]
4. Contact name.......................         [check]          [check]
5. Contact phone number...............         [check]          [check]
6. FIPS code..........................         [check]          [check]
7. SCC................................         [check]          [check]
8. Emission factor....................         [check]          [check]
9. Activity (VMT by SCC)..............         [check]          [check]
10. Pollutant code....................         [check]          [check]
11. Ozone season emissions (if                 [check]          [check]
 applicable)..........................
12. Summer day emissions (if                   [check]          [check]
 applicable)..........................
13. Annual emissions..................         [check]          [check]
14. Winter throughput (percent).......         [check]          [check]

[[Page 152]]

 
15. Spring throughput (percent).......         [check]          [check]
16. Summer throughput (percent).......         [check]          [check]
17. Fall throughput (percent).........         [check]          [check]
18. Winter work weekday emissions of    ...............         [check]
 CO (if applicable)...................
------------------------------------------------------------------------

Subparts B-E [Reserved]



                    Subpart F_Procedural Requirements

    Authority: 42 U.S.C. 7401, 7411, 7412, 7413, 7414, 7470-7479, 7501-
7508, 7601, and 7602.



Sec. 51.100  Definitions.

    As used in this part, all terms not defined herein will have the 
meaning given them in the Act:
    (a) Act means the Clean Air Act (42 U.S.C. 7401 et seq., as amended 
by Pub. L. 91-604, 84 Stat. 1676 Pub. L. 95-95, 91 Stat., 685 and Pub. 
L. 95-190, 91 Stat., 1399.)
    (b) Administrator means the Administrator of the Environmental 
Protection Agency (EPA) or an authorized representative.
    (c) Primary standard means a national primary ambient air quality 
standard promulgated pursuant to section 109 of the Act.
    (d) Secondary standard means a national secondary ambient air 
quality standard promulgated pursuant to section 109 of the Act.
    (e) National standard means either a primary or secondary standard.
    (f) Owner or operator means any person who owns, leases, operates, 
controls, or supervises a facility, building, structure, or installation 
which directly or indirectly result or may result in emissions of any 
air pollutant for which a national standard is in effect.
    (g) Local agency means any local government agency other than the 
State agency, which is charged with responsibility for carrying out a 
portion of the plan.
    (h) Regional Office means one of the ten (10) EPA Regional Offices.
    (i) State agency means the air pollution control agency primarily 
responsible for development and implementation of a plan under the Act.
    (j) Plan means an implementation plan approved or promulgated under 
section 110 of 172 of the Act.
    (k) Point source means the following:
    (1) For particulate matter, sulfur oxides, carbon monoxide, volatile 
organic compounds (VOC) and nitrogen dioxide--
    (i) Any stationary source the actual emissions of which are in 
excess of 90.7 metric tons (100 tons) per year of the pollutant in a 
region containing an area whose 1980 urban place population, as defined 
by the U.S. Bureau of the Census, was equal to or greater than 1 
million.
    (ii) Any stationary source the actual emissions of which are in 
excess of 22.7 metric tons (25 tons) per year of the pollutant in a 
region containing an area whose 1980 urban place population, as defined 
by the U.S. Bureau of the Census, was less than 1 million; or
    (2) For lead or lead compounds measured as elemental lead, any 
stationary source that actually emits a total of 4.5 metric tons (5 
tons) per year or more.
    (l) Area source means any small residential, governmental, 
institutional, commercial, or industrial fuel combustion operations; 
onsite solid waste disposal facility; motor vehicles, aircraft vessels, 
or other transportation facilities or other miscellaneous sources 
identified through inventory techniques similar to those described in 
the ``AEROS Manual series, Vol. II AEROS User's Manual,'' EPA-450/2-76-
029 December 1976.
    (m) Region means an area designated as an air quality control region 
(AQCR) under section 107(c) of the Act.
    (n) Control strategy means a combination of measures designated to 
achieve the aggregate reduction of emissions

[[Page 153]]

necessary for attainment and maintenance of national standards 
including, but not limited to, measures such as:
    (1) Emission limitations.
    (2) Federal or State emission charges or taxes or other economic 
incentives or disincentives.
    (3) Closing or relocation of residential, commercial, or industrial 
facilities.
    (4) Changes in schedules or methods of operation of commercial or 
industrial facilities or transportation systems, including, but not 
limited to, short-term changes made in accordance with standby plans.
    (5) Periodic inspection and testing of motor vehicle emission 
control systems, at such time as the Administrator determines that such 
programs are feasible and practicable.
    (6) Emission control measures applicable to in-use motor vehicles, 
including, but not limited to, measures such as mandatory maintenance, 
installation of emission control devices, and conversion to gaseous 
fuels.
    (7) Any transportation control measure including those 
transportation measures listed in section 108(f) of the Clean Air Act as 
amended.
    (8) Any variation of, or alternative to any measure delineated 
herein.
    (9) Control or prohibition of a fuel or fuel additive used in motor 
vehicles, if such control or prohibition is necessary to achieve a 
national primary or secondary air quality standard and is approved by 
the Administrator under section 211(c)(4)(C) of the Act.
    (o) Reasonably available control technology (RACT) means devices, 
systems, process modifications, or other apparatus or techniques that 
are reasonably available taking into account:
    (1) The necessity of imposing such controls in order to attain and 
maintain a national ambient air quality standard;
    (2) The social, environmental, and economic impact of such controls; 
and
    (3) Alternative means of providing for attainment and maintenance of 
such standard. (This provision defines RACT for the purposes of Sec. 
51.341(b) only.)
    (p) Compliance schedule means the date or dates by which a source or 
category of sources is required to comply with specific emission 
limitations contained in an implementation plan and with any increments 
of progress toward such compliance.
    (q) Increments of progress means steps toward compliance which will 
be taken by a specific source, including:
    (1) Date of submittal of the source's final control plan to the 
appropriate air pollution control agency;
    (2) Date by which contracts for emission control systems or process 
modifications will be awarded; or date by which orders will be issued 
for the purchase of component parts to accomplish emission control or 
process modification;
    (3) Date of initiation of on-site construction or installation of 
emission control equipment or process change;
    (4) Date by which on-site construction or installation of emission 
control equipment or process modification is to be completed; and
    (5) Date by which final compliance is to be achieved.
    (r) Transportation control measure means any measure that is 
directed toward reducing emissions of air pollutants from transportation 
sources. Such measures include, but are not limited to, those listed in 
section 108(f) of the Clean Air Act.
    (s) Volatile organic compounds (VOC) means any compound of carbon, 
excluding carbon monoxide, carbon dioxide, carbonic acid, metallic 
carbides or carbonates, and ammonium carbonate, which participates in 
atmospheric photochemical reactions.
    (1) This includes any such organic compound other than the 
following, which have been determined to have negligible photochemical 
reactivity: methane; ethane; methylene chloride (dichloromethane); 
1,1,1-trichloroethane (methyl chloroform); 1,1,2-trichloro-1,2,2-
trifluoroethane (CFC-113); trichlorofluoromethane (CFC-11); 
dichlorodifluoromethane (CFC-12); chlorodifluoromethane (HCFC-22); 
trifluoromethane (HFC-23); 1,2-dichloro 1,1,2,2-tetrafluoroethane (CFC-
114); chloropentafluoroethane (CFC-115); 1,1,1-trifluoro 2,2-
dichloroethane (HCFC-123); 1,1,1,2-tetrafluoroethane (HFC-134a); 1,1-
dichloro 1-fluoroethane (HCFC-141b); 1-chloro 1,1-difluoroethane (HCFC-
142b); 2-chloro-1,1,1,2-tetrafluoroethane (HCFC-124);

[[Page 154]]

pentafluoroethane (HFC-125); 1,1,2,2-tetrafluoroethane (HFC-134); 1,1,1-
trifluoroethane (HFC-143a); 1,1-difluoroethane (HFC-152a); 
parachlorobenzotrifluoride (PCBTF); cyclic, branched, or linear 
completely methylated siloxanes; acetone; perchloroethylene 
(tetrachloroethylene); 3,3-dichloro-1,1,1,2,2-pentafluoropropane (HCFC-
225ca); 1,3-dichloro-1,1,2,2,3-pentafluoropropane (HCFC-225cb); 
1,1,1,2,3,4,4,5,5,5-decafluoropentane (HFC 43-10mee); difluoromethane 
(HFC-32); ethylfluoride (HFC-161); 1,1,1,3,3,3-hexafluoropropane (HFC-
236fa); 1,1,2,2,3-pentafluoropropane (HFC-245ca); 1,1,2,3,3-
pentafluoropropane (HFC-245ea); 1,1,1,2,3-pentafluoropropane (HFC-
245eb); 1,1,1,3,3-pentafluoropropane (HFC-245fa); 1,1,1,2,3,3-
hexafluoropropane (HFC-236ea); 1,1,1,3,3-pentafluorobutane (HFC-365mfc); 
chlorofluoromethane (HCFC-31); 1 chloro-1-fluoroethane (HCFC-151a); 1,2-
dichloro-1,1,2-trifluoroethane (HCFC-123a); 1,1,1,2,2,3,3,4,4-
nonafluoro-4-methoxy-butane (C4F9OCH3 
or HFE-7100); 2-(difluoromethoxymethyl)-1,1,1,2,3,3,3-heptafluoropropane 
((CF3)2CFCF2OCH3); 1-ethoxy-
1,1,2,2,3,3,4,4,4-nonafluorobutane 
(C4F9OC2H5 or HFE-7200); 2-
(ethoxydifluoromethyl)-1,1,1,2,3,3,3-heptafluoropropane 
((CF3)2CFCF2OC2H5)
; methyl acetate, 1,1,1,2,2,3,3-heptafluoro-3-methoxy-propane (n-
C3F7OCH3, HFE-7000), 3-ethoxy-
1,1,1,2,3,4,4,5,5,6,6,6-dodecafluoro-2-(trifluoromethyl) hexane (HFE-
7500), 1,1,1,2,3,3,3-heptafluoropropane (HFC 227ea), methyl formate 
(HCOOCH3), (1) 1,1,1,2,2,3,4,5,5,5-decafluoro-3-methoxy-4-
trifluoromethyl-pentane (HFE-7300); propylene carbonate; dimethyl 
carbonate; and perfluorocarbon compounds which fall into these classes:
    (i) Cyclic, branched, or linear, completely fluorinated alkanes;
    (ii) Cyclic, branched, or linear, completely fluorinated ethers with 
no unsaturations;
    (iii) Cyclic, branched, or linear, completely fluorinated tertiary 
amines with no unsaturations; and
    (iv) Sulfur containing perfluorocarbons with no unsaturations and 
with sulfur bonds only to carbon and fluorine.
    (2) For purposes of determining compliance with emissions limits, 
VOC will be measured by the test methods in the approved State 
implementation plan (SIP) or 40 CFR part 60, appendix A, as applicable. 
Where such a method also measures compounds with negligible 
photochemical reactivity, these negligibility-reactive compounds may be 
excluded as VOC if the amount of such compounds is accurately 
quantified, and such exclusion is approved by the enforcement authority.
    (3) As a precondition to excluding these compounds as VOC or at any 
time thereafter, the enforcement authority may require an owner or 
operator to provide monitoring or testing methods and results 
demonstrating, to the satisfaction of the enforcement authority, the 
amount of negligibly-reactive compounds in the source's emissions.
    (4) For purposes of Federal enforcement for a specific source, the 
EPA shall use the test methods specified in the applicable EPA-approved 
SIP, in a permit issued pursuant to a program approved or promulgated 
under title V of the Act, or under 40 CFR part 51, subpart I or appendix 
S, or under 40 CFR parts 52 or 60. The EPA shall not be bound by any 
State determination as to appropriate methods for testing or monitoring 
negligibly-reactive compounds if such determination is not reflected in 
any of the above provisions.
    (5) The following compound(s) are VOC for purposes of all 
recordkeeping, emissions reporting, photochemical dispersion modeling 
and inventory requirements which apply to VOC and shall be uniquely 
identified in emission reports, but are not VOC for purposes of VOC 
emissions limitations or VOC content requirements: t-butyl acetate.
    (6) For the purposes of determining compliance with California's 
aerosol coatings reactivity-based regulation, (as described in the 
California Code of Regulations, Title 17, Division 3, Chapter 1, 
Subchapter 8.5, Article 3), any organic compound in the volatile portion 
of an aerosol coating is counted towards that product's reactivity-based 
limit. Therefore, the compounds identified in paragraph (s) of this 
section as

[[Page 155]]

negligibly reactive and excluded from EPA's definition of VOCs are to be 
counted towards a product's reactivity limit for the purposes of 
determining compliance with California's aerosol coatings reactivity-
based regulation.
    (7) For the purposes of determining compliance with EPA's aerosol 
coatings reactivity based regulation (as described in 40 CFR part 59--
National Volatile Organic Compound Emission Standards for Consumer and 
Commercial Products) any organic compound in the volatile portion of an 
aerosol coating is counted towards the product's reactivity-based limit, 
as provided in 40 CFR part 59, subpart E. Therefore, the compounds that 
are used in aerosol coating products and that are identified in 
paragraphs (s)(1) or (s)(5) of this section as excluded from EPA's 
definition of VOC are to be counted towards a product's reactivity limit 
for the purposes of determining compliance with EPA's aerosol coatings 
reactivity-based national regulation, as provided in 40 CFR part 59, 
subpart E.
    (t)-(w) [Reserved]
    (x) Time period means any period of time designated by hour, month, 
season, calendar year, averaging time, or other suitable 
characteristics, for which ambient air quality is estimated.
    (y) Variance means the temporary deferral of a final compliance date 
for an individual source subject to an approved regulation, or a 
temporary change to an approved regulation as it applies to an 
individual source.
    (z) Emission limitation and emission standard mean a requirement 
established by a State, local government, or the Administrator which 
limits the quantity, rate, or concentration of emissions of air 
pollutants on a continuous basis, including any requirements which limit 
the level of opacity, prescribe equipment, set fuel specifications, or 
prescribe operation or maintenance procedures for a source to assure 
continuous emission reduction.
    (aa) Capacity factor means the ratio of the average load on a 
machine or equipment for the period of time considered to the capacity 
rating of the machine or equipment.
    (bb) Excess emissions means emissions of an air pollutant in excess 
of an emission standard.
    (cc) Nitric acid plant means any facility producing nitric acid 30 
to 70 percent in strength by either the pressure or atmospheric pressure 
process.
    (dd) Sulfuric acid plant means any facility producing sulfuric acid 
by the contact process by burning elemental sulfur, alkylation acid, 
hydrogen sulfide, or acid sludge, but does not include facilities where 
conversion to sulfuric acid is utilized primarily as a means of 
preventing emissions to the atmosphere of sulfur dioxide or other sulfur 
compounds.
    (ee) Fossil fuel-fired steam generator means a furnance or bioler 
used in the process of burning fossil fuel for the primary purpose of 
producing steam by heat transfer.
    (ff) Stack means any point in a source designed to emit solids, 
liquids, or gases into the air, including a pipe or duct but not 
including flares.
    (gg) A stack in existence means that the owner or operator had (1) 
begun, or caused to begin, a continuous program of physical on-site 
construction of the stack or (2) entered into binding agreements or 
contractual obligations, which could not be cancelled or modified 
without substantial loss to the owner or operator, to undertake a 
program of construction of the stack to be completed within a reasonable 
time.
    (hh)(1) Dispersion technique means any technique which attempts to 
affect the concentration of a pollutant in the ambient air by:
    (i) Using that portion of a stack which exceeds good engineering 
practice stack height:
    (ii) Varying the rate of emission of a pollutant according to 
atmospheric conditions or ambient concentrations of that pollutant; or
    (iii) Increasing final exhaust gas plume rise by manipulating source 
process parameters, exhaust gas parameters, stack parameters, or 
combining exhaust gases from several existing stacks into one stack; or 
other selective handling of exhaust gas streams so as to increase the 
exhaust gas plume rise.
    (2) The preceding sentence does not include:

[[Page 156]]

    (i) The reheating of a gas stream, following use of a pollution 
control system, for the purpose of returning the gas to the temperature 
at which it was originally discharged from the facility generating the 
gas stream;
    (ii) The merging of exhaust gas streams where:
    (A) The source owner or operator demonstrates that the facility was 
originally designed and constructed with such merged gas streams;
    (B) After July 8, 1985 such merging is part of a change in operation 
at the facility that includes the installation of pollution controls and 
is accompanied by a net reduction in the allowable emissions of a 
pollutant. This exclusion from the definition of dispersion techniques 
shall apply only to the emission limitation for the pollutant affected 
by such change in operation; or
    (C) Before July 8, 1985, such merging was part of a change in 
operation at the facility that included the installation of emissions 
control equipment or was carried out for sound economic or engineering 
reasons. Where there was an increase in the emission limitation or, in 
the event that no emission limitation was in existence prior to the 
merging, an increase in the quantity of pollutants actually emitted 
prior to the merging, the reviewing agency shall presume that merging 
was significantly motivated by an intent to gain emissions credit for 
greater dispersion. Absent a demonstration by the source owner or 
operator that merging was not significantly motivated by such intent, 
the reviewing agency shall deny credit for the effects of such merging 
in calculating the allowable emissions for the source;
    (iii) Smoke management in agricultural or silvicultural prescribed 
burning programs;
    (iv) Episodic restrictions on residential woodburning and open 
burning; or
    (v) Techniques under Sec. 51.100(hh)(1)(iii) which increase final 
exhaust gas plume rise where the resulting allowable emissions of sulfur 
dioxide from the facility do not exceed 5,000 tons per year.
    (ii) Good engineering practice (GEP) stack height means the greater 
of:
    (1) 65 meters, measured from the ground-level elevation at the base 
of the stack:
    (2)(i) For stacks in existence on January 12, 1979, and for which 
the owner or operator had obtained all applicable permits or approvals 
required under 40 CFR parts 51 and 52.

Hg = 2.5H,


provided the owner or operator produces evidence that this equation was 
actually relied on in establishing an emission limitation:
    (ii) For all other stacks,

Hg = H + 1.5L

where:

Hg = good engineering practice stack height, measured from 
the ground-level elevation at the base of the stack,
H = height of nearby structure(s) measured from the ground-level 
elevation at the base of the stack.
L = lesser dimension, height or projected width, of nearby structure(s)


provided that the EPA, State or local control agency may require the use 
of a field study or fluid model to verify GEP stack height for the 
source; or
    (3) The height demonstrated by a fluid model or a field study 
approved by the EPA State or local control agency, which ensures that 
the emissions from a stack do not result in excessive concentrations of 
any air pollutant as a result of atmospheric downwash, wakes, or eddy 
effects created by the source itself, nearby structures or nearby 
terrain features.
    (jj) Nearby as used in Sec. 51.100(ii) of this part is defined for 
a specific structure or terrain feature and
    (1) For purposes of applying the formulae provided in Sec. 
51.100(ii)(2) means that distance up to five times the lesser of the 
height or the width dimension of a structure, but not greater than 0.8 
km (\1/2\ mile), and
    (2) For conducting demonstrations under Sec. 51.100(ii)(3) means 
not greater than 0.8 km (\1/2\ mile), except that the portion of a 
terrain feature may be considered to be nearby which falls within a 
distance of up to 10 times the maximum height (Ht) of the 
feature, not to exceed 2 miles if such feature achieves a height 
(Ht) 0.8 km from the stack that is at least 40 percent of the

[[Page 157]]

GEP stack height determined by the formulae provided in Sec. 
51.100(ii)(2)(ii) of this part or 26 meters, whichever is greater, as 
measured from the ground-level elevation at the base of the stack. The 
height of the structure or terrain feature is measured from the ground-
level elevation at the base of the stack.
    (kk) Excessive concentration is defined for the purpose of 
determining good engineering practice stack height under Sec. 
51.100(ii)(3) and means:
    (1) For sources seeking credit for stack height exceeding that 
established under Sec. 51.100(ii)(2) a maximum ground-level 
concentration due to emissions from a stack due in whole or part to 
downwash, wakes, and eddy effects produced by nearby structures or 
nearby terrain features which individually is at least 40 percent in 
excess of the maximum concentration experienced in the absence of such 
downwash, wakes, or eddy effects and which contributes to a total 
concentration due to emissions from all sources that is greater than an 
ambient air quality standard. For sources subject to the prevention of 
significant deterioration program (40 CFR 51.166 and 52.21), an 
excessive concentration alternatively means a maximum ground-level 
concentration due to emissions from a stack due in whole or part to 
downwash, wakes, or eddy effects produced by nearby structures or nearby 
terrain features which individually is at least 40 percent in excess of 
the maximum concentration experienced in the absence of such downwash, 
wakes, or eddy effects and greater than a prevention of significant 
deterioration increment. The allowable emission rate to be used in 
making demonstrations under this part shall be prescribed by the new 
source performance standard that is applicable to the source category 
unless the owner or operator demonstrates that this emission rate is 
infeasible. Where such demonstrations are approved by the authority 
administering the State implementation plan, an alternative emission 
rate shall be established in consultation with the source owner or 
operator.
    (2) For sources seeking credit after October 11, 1983, for increases 
in existing stack heights up to the heights established under Sec. 
51.100(ii)(2), either (i) a maximum ground-level concentration due in 
whole or part to downwash, wakes or eddy effects as provided in 
paragraph (kk)(1) of this section, except that the emission rate 
specified by any applicable State implementation plan (or, in the 
absence of such a limit, the actual emission rate) shall be used, or 
(ii) the actual presence of a local nuisance caused by the existing 
stack, as determined by the authority administering the State 
implementation plan; and
    (3) For sources seeking credit after January 12, 1979 for a stack 
height determined under Sec. 51.100(ii)(2) where the authority 
administering the State implementation plan requires the use of a field 
study or fluid model to verify GEP stack height, for sources seeking 
stack height credit after November 9, 1984 based on the aerodynamic 
influence of cooling towers, and for sources seeking stack height credit 
after December 31, 1970 based on the aerodynamic influence of structures 
not adequately represented by the equations in Sec. 51.100(ii)(2), a 
maximum ground-level concentration due in whole or part to downwash, 
wakes or eddy effects that is at least 40 percent in excess of the 
maximum concentration experienced in the absence of such downwash, 
wakes, or eddy effects.
    (ll)-(mm) [Reserved]
    (nn) Intermittent control system (ICS) means a dispersion technique 
which varies the rate at which pollutants are emitted to the atmosphere 
according to meteorological conditions and/or ambient concentrations of 
the pollutant, in order to prevent ground-level concentrations in excess 
of applicable ambient air quality standards. Such a dispersion technique 
is an ICS whether used alone, used with other dispersion techniques, or 
used as a supplement to continuous emission controls (i.e., used as a 
supplemental control system).
    (oo) Particulate matter means any airborne finely divided solid or 
liquid material with an aerodynamic diameter smaller than 100 
micrometers.
    (pp) Particulate matter emissions means all finely divided solid or 
liquid material, other than uncombined water, emitted to the ambient air 
as measured

[[Page 158]]

by applicable reference methods, or an equivalent or alternative method, 
specified in this chapter, or by a test method specified in an approved 
State implementation plan.
    (qq) PM10 means particulate matter with an aerodynamic 
diameter less than or equal to a nominal 10 micrometers as measured by a 
reference method based on appendix J of part 50 of this chapter and 
designated in accordance with part 53 of this chapter or by an 
equivalent method designated in accordance with part 53 of this chapter.
    (rr) PM10 emissions means finely divided solid or liquid 
material, with an aerodynamic diameter less than or equal to a nominal 
10 micrometers emitted to the ambient air as measured by an applicable 
reference method, or an equivalent or alternative method, specified in 
this chapter or by a test method specified in an approved State 
implementation plan.
    (ss) Total suspended particulate means particulate matter as 
measured by the method described in appendix B of part 50 of this 
chapter.

[51 FR 40661, Nov. 7, 1986, as amended at 52 FR 24712, July 1, 1987; 57 
FR 3945, Feb. 3, 1992; 61 FR 4590, Feb. 7, 1996; 61 FR 16060, Apr. 11, 
1996; 61 FR 30162, June 14, 1996; 61 FR 52850, Oct. 8, 1996; 62 FR 
44903, Aug. 25, 1997; 63 FR 9151, Feb. 24, 1998; 63 FR 17333, Apr. 9, 
1998; 69 FR 69298, 69304, Nov. 29, 2004; 70 FR 53935, Sept. 13, 2005; 72 
FR 2196, Jan. 18, 2007; 73 FR 15620, Mar. 24, 2008; 74 FR 3441, Jan. 21, 
2009; 74 FR 29603, June 23, 2009]



Sec. 51.101  Stipulations.

    Nothing in this part will be construed in any manner:
    (a) To encourage a State to prepare, adopt, or submit a plan which 
does not provide for the protection and enhancement of air quality so as 
to promote the public health and welfare and productive capacity.
    (b) To encourage a State to adopt any particular control strategy 
without taking into consideration the cost-effectiveness of such control 
strategy in relation to that of alternative control strategies.
    (c) To preclude a State from employing techniques other than those 
specified in this part for purposes of estimating air quality or 
demonstrating the adequacy of a control strategy, provided that such 
other techniques are shown to be adequate and appropriate for such 
purposes.
    (d) To encourage a State to prepare, adopt, or submit a plan without 
taking into consideration the social and economic impact of the control 
strategy set forth in such plan, including, but not limited to, impact 
on availability of fuels, energy, transportation, and employment.
    (e) To preclude a State from preparing, adopting, or submitting a 
plan which provides for attainment and maintenance of a national 
standard through the application of a control strategy not specifically 
identified or described in this part.
    (f) To preclude a State or political subdivision thereof from 
adopting or enforcing any emission limitations or other measures or 
combinations thereof to attain and maintain air quality better than that 
required by a national standard.
    (g) To encourage a State to adopt a control strategy uniformly 
applicable throughout a region unless there is no satisfactory 
alternative way of providing for attainment and maintenance of a 
national standard throughout such region.

[61 FR 30163, June 14, 1996]



Sec. 51.102  Public hearings.

    (a) Except as otherwise provided in paragraph (c) of this section 
and within the 30 day notification period as required by paragraph (d) 
of this section, States must provide notice, provide the opportunity to 
submit written comments and allow the public the opportunity to request 
a public hearing. The State must hold a public hearing or provide the 
public the opportunity to request a public hearing. The notice 
announcing the 30 day notification period must include the date, place 
and time of the public hearing. If the State provides the public the 
opportunity to request a public hearing and a request is received the 
State must hold the scheduled hearing or schedule a public hearing (as 
required by paragraph (d) of this section). The State may cancel the 
public hearing through a method it identifies if no request for a public 
hearing is received during the 30 day notification period and the 
original notice announcing the 30 day notification

[[Page 159]]

period clearly states: If no request for a public hearing is received 
the hearing will be cancelled; identifies the method and time for 
announcing that the hearing has been cancelled; and provides a contact 
phone number for the public to call to find out if the hearing has been 
cancelled. These requirements apply for adoption and submission to EPA 
of:
    (1) Any plan or revision of it required by Sec. 51.104(a).
    (2) Any individual compliance schedule under (Sec. 51.260).
    (3) Any revision under Sec. 51.104(d).
    (b) Separate hearings may be held for plans to implement primary and 
secondary standards.
    (c) No hearing will be required for any change to an increment of 
progress in an approved individual compliance schedule unless such 
change is likely to cause the source to be unable to comply with the 
final compliance date in the schedule. The requirements of Sec. Sec. 
51.104 and 51.105 will be applicable to such schedules, however.
    (d) Any hearing required by paragraph (a) of this section will be 
held only after reasonable notice, which will be considered to include, 
at least 30 days prior to the date of such hearing(s):
    (1) Notice given to the public by prominent advertisement in the 
area affected announcing the date(s), time(s), and place(s) of such 
hearing(s);
    (2) Availability of each proposed plan or revision for public 
inspection in at least one location in each region to which it will 
apply, and the availability of each compliance schedule for public 
inspection in at least one location in the region in which the affected 
source is located;
    (3) Notification to the Administrator (through the appropriate 
Regional Office);
    (4) Notification to each local air pollution control agency which 
will be significantly impacted by such plan, schedule or revision;
    (5) In the case of an interstate region, notification to any other 
States included, in whole or in part, in the regions which are 
significantly impacted by such plan or schedule or revision.
    (e) The State must prepare and retain, for inspection by the 
Administrator upon request, a record of each hearing. The record must 
contain, as a minimum, a list of witnesses together with the text of 
each presentation.
    (f) The State must submit with the plan, revision, or schedule, a 
certification that the requirements in paragraph (a) and (d) of this 
section were met. Such certification will include the date and place of 
any public hearing(s) held or that no public hearing was requested 
during the 30 day notification period.
    (g) Upon written application by a State agency (through the 
appropriate Regional Office), the Administrator may approve State 
procedures for public hearings. The following criteria apply:
    (1) Procedures approved under this section shall be deemed to 
satisfy the requirement of this part regarding public hearings.
    (2) Procedures different from this part may be approved if they--
    (i) Ensure public participation in matters for which hearings are 
required; and
    (ii) Provide adequate public notification of the opportunity to 
participate.
    (3) The Administrator may impose any conditions on approval he or 
she deems necessary.

[36 FR 22938, Nov. 25, 1971, as amended at 65 FR 8657, Feb. 22, 2000; 72 
FR 38792, July 16, 2007]



Sec. 51.103  Submission of plans, preliminary review of plans.

    (a) The State makes an official plan submission to EPA only when the 
submission conforms to the requirements of appendix V to this part, and 
the State delivers five hard copies or at least two hard copies with an 
electronic version of the hard copy (unless otherwise agreed to by the 
State and Regional Office) of the plan to the appropriate Regional 
Office, with a letter giving notice of such action. If the State submits 
an electronic copy, it must be an exact duplicate of the hard copy.
    (b) Upon request of a State, the Administrator will provide 
preliminary review of a plan or portion thereof submitted in advance of 
the date such plan is due. Such requests must be made in writing to the 
appropriate Regional Office, must indicate changes (such as,

[[Page 160]]

redline/strikethrough) to the existing approved plan, where applicable 
and must be accompanied by five hard copies or at least two hard copies 
with an electronic version of the hard copy (unless otherwise agreed to 
by the State and Regional Office). Requests for preliminary review do 
not relieve a State of the responsibility of adopting and submitting 
plans in accordance with prescribed due dates.

[72 FR 38792, July 16, 2007]



Sec. 51.104  Revisions.

    (a) States may revise the plan from time to time consistent with the 
requirements applicable to implementation plans under this part.
    (b) The States must submit any revision of any regulation or any 
compliance schedule under paragraph (c) of this section to the 
Administrator no later than 60 days after its adoption.
    (c) EPA will approve revisions only after applicable hearing 
requirements of Sec. 51.102 have been satisfied.
    (d) In order for a variance to be considered for approval as a 
revision to the State implementation plan, the State must submit it in 
accordance with the requirements of this section.

[51 FR 40661, Nov. 7, 1986, as amended at 61 FR 16060, Apr. 11, 1996]



Sec. 51.105  Approval of plans.

    Revisions of a plan, or any portion thereof, will not be considered 
part of an applicable plan until such revisions have been approved by 
the Administrator in accordance with this part.

[51 FR 40661, Nov. 7, 1986, as amended at 60 FR 33922, June 29, 1995]



                       Subpart G_Control Strategy

    Source: 51 FR 40665, Nov. 7, 1986, unless otherwise noted.



Sec. 51.110  Attainment and maintenance of national standards.

    (a) Each plan providing for the attainment of a primary or secondary 
standard must specify the projected attainment date.
    (b)-(f) [Reserved]
    (g) During developing of the plan, EPA encourages States to identify 
alternative control strategies, as well as the costs and benefits of 
each such alternative for attainment or maintenance of the national 
standard.

[51 FR 40661 Nov. 7, 1986 as amended at 61 FR 16060, Apr. 11, 1996; 61 
FR 30163, June 14, 1996]



Sec. 51.111  Description of control measures.

    Each plan must set forth a control strategy which includes the 
following:
    (a) A description of enforcement methods including, but not limited 
to:
    (1) Procedures for monitoring compliance with each of the selected 
control measures,
    (2) Procedures for handling violations, and
    (3) A designation of agency responsibility for enforcement of 
implementation.
    (b) [Reserved]

[51 FR 40665, Nov. 7, 1986, as amended at 60 FR 33922, June 29, 1995]



Sec. 51.112  Demonstration of adequacy.

    (a) Each plan must demonstrate that the measures, rules, and 
regulations contained in it are adequate to provide for the timely 
attainment and maintenance of the national standard that it implements.
    (1) The adequacy of a control strategy shall be demonstrated by 
means of applicable air quality models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a modification or 
substitution of a model may be made on a case-by-case basis or, where 
appropriate, on a generic basis for a specific State program. Written 
approval of the Administrator must be obtained for any modification or 
substitution. In addition, use of a modified or substituted model must 
be subject to notice and opportunity for public comment under procedures 
set forth in Sec. 51.102.
    (b) The demonstration must include the following:
    (1) A summary of the computations, assumptions, and judgments used 
to determine the degree of reduction of emissions (or reductions in the 
growth

[[Page 161]]

of emissions) that will result from the implementation of the control 
strategy.
    (2) A presentation of emission levels expected to result from 
implementation of each measure of the control strategy.
    (3) A presentation of the air quality levels expected to result from 
implementation of the overall control strategy presented either in 
tabular form or as an isopleth map showing expected maximum pollutant 
concentrations.
    (4) A description of the dispersion models used to project air 
quality and to evaluate control strategies.
    (5) For interstate regions, the analysis from each constituent State 
must, where practicable, be based upon the same regional emission 
inventory and air quality baseline.

[51 FR 40665, Nov. 7, 1986, as amended at 58 FR 38821, July 20, 1993; 60 
FR 40468, Aug. 9, 1995; 61 FR 41840, Aug. 12, 1996]



Sec. 51.113  [Reserved]



Sec. 51.114  Emissions data and projections.

    (a) Except for lead, each plan must contain a detailed inventory of 
emissions from point and area sources. Lead requirements are specified 
in Sec. 51.117. The inventory must be based upon measured emissions or, 
where measured emissions are not available, documented emission factors.
    (b) Each plan must contain a summary of emission levels projected to 
result from application of the new control strategy.
    (c) Each plan must identify the sources of the data used in the 
projection of emissions.



Sec. 51.115  Air quality data and projections.

    (a) Each plan must contain a summary of data showing existing air 
quality.
    (b) Each plan must:
    (1) Contain a summary of air quality concentrations expected to 
result from application of the control strategy, and
    (2) Identify and describe the dispersion model, other air quality 
model, or receptor model used.
    (c) Actual measurements of air quality must be used where available 
if made by methods specified in appendix C to part 58 of this chapter. 
Estimated air quality using appropriate modeling techniques may be used 
to supplement measurements.
    (d) For purposes of developing a control strategy, background 
concentration shall be taken into consideration with respect to 
particulate matter. As used in this subpart, background concentration is 
that portion of the measured ambient levels that cannot be reduced by 
controlling emissions from man-made sources.
    (e) In developing an ozone control strategy for a particular area, 
background ozone concentrations and ozone transported into an area must 
be considered. States may assume that the ozone standard will be 
attained in upwind areas.



Sec. 51.116  Data availability.

    (a) The State must retain all detailed data and calculations used in 
the preparation of each plan or each plan revision, and make them 
available for public inspection and submit them to the Administrator at 
his request.
    (b) The detailed data and calculations used in the preparation of 
plan revisions are not considered a part of the plan.
    (c) Each plan must provide for public availability of emission data 
reported by source owners or operators or otherwise obtained by a State 
or local agency. Such emission data must be correlated with applicable 
emission limitations or other measures. As used in this paragraph, 
correlated means presented in such a manner as to show the relationship 
between measured or estimated amounts of emissions and the amounts of 
such emissions allowable under the applicable emission limitations or 
other measures.



Sec. 51.117  Additional provisions for lead.

    In addition to other requirements in Sec. Sec. 51.100 through 
51.116 the following requirements apply to lead. To the extent they 
conflict, there requirements are controlling over those of the 
proceeding sections.
    (a) Control strategy demonstration. Each plan must contain a 
demonstration showing that the plan will attain

[[Page 162]]

and maintain the standard in the following areas:
    (1) Areas in the vicinity of the following point sources of lead: 
Primary lead smelters, Secondary lead smelters, Primary copper smelters, 
Lead gasoline additive plants, Lead-acid storage battery manufacturing 
plants that produce 2,000 or more batteries per day. Any other 
stationary source that actually emits 25 or more tons per year of lead 
or lead compounds measured as elemental lead.
    (2) Any other area that has lead air concentrations in excess of the 
national ambient air quality standard concentration for lead, measured 
since January 1, 1974.
    (b) Time period for demonstration of adequacy. The demonstration of 
adequacy of the control strategy required under Sec. 51.112 may cover a 
longer period if allowed by the appropriate EPA Regional Administrator.
    (c) Special modeling provisions. (1) For urbanized areas with 
measured lead concentrations in excess of 4.0 [micro]g/m\3\, quarterly 
mean measured since January 1, 1974, the plan must employ the modified 
rollback model for the demonstration of attainment as a minimum, but may 
use an atmospheric dispersion model if desired, consistent with 
requirements contained in Sec. 51.112(a). If a proportional model is 
used, the air quality data should be the same year as the emissions 
inventory required under the paragraph e.
    (2) For each point source listed in Sec. 51.117(a), that plan must 
employ an atmospheric dispersion model for demonstration of attainment, 
consistent with requirements contained in Sec. 51.112(a).
    (3) For each area in the vicinity of an air quality monitor that has 
recorded lead concentrations in excess of the lead national standard 
concentration, the plan must employ the modified rollback model as a 
minimum, but may use an atmospheric dispersion model if desired for the 
demonstration of attainment, consistent with requirements contained in 
Sec. 51.112(a).
    (d) Air quality data and projections. (1) Each State must submit to 
the appropriate EPA Regional Office with the plan, but not part of the 
plan, all lead air quality data measured since January 1, 1974. This 
requirement does not apply if the data has already been submitted.
    (2) The data must be submitted in accordance with the procedures and 
data forms specified in Chapter 3.4.0 of the ``AEROS User's Manual'' 
concerning storage and retrieval of aerometric data (SAROAD) except 
where the Regional Administrator waives this requirement.
    (3) If additional lead air quality data are desired to determine 
lead air concentrations in areas suspected of exceeding the lead 
national ambient air quality standard, the plan may include data from 
any previously collected filters from particulate matter high volume 
samplers. In determining the lead content of the filters for control 
strategy demonstration purposes, a State may use, in addition to the 
reference method, X-ray fluorescence or any other method approved by the 
Regional Administrator.
    (e) Emissions data. (1) The point source inventory on which the 
summary of the baseline for lead emissions inventory is based must 
contain all sources that emit 0.5 or more tons of lead per year.
    (2) Each State must submit lead emissions data to the appropriate 
EPA Regional Office with the original plan. The submission must be made 
with the plan, but not as part of the plan, and must include emissions 
data and information related to point and area source emissions. The 
emission data and information should include the information identified 
in the Hazardous and Trace Emissions System (HATREMS) point source 
coding forms for all point sources and the area source coding forms for 
all sources that are not point sources, but need not necessarily be in 
the format of those forms.

[41 FR 18388, May 3, 1976, as amended at 58 FR 38822, July 20, 1993; 73 
FR 67057, Nov. 12, 2008]



Sec. 51.118  Stack height provisions.

    (a) The plan must provide that the degree of emission limitation 
required of any source for control of any air pollutant must not be 
affected by so much of any source's stack height that exceeds good 
engineering practice or by

[[Page 163]]

any other dispersion technique, except as provided in Sec. 51.118(b). 
The plan must provide that before a State submits to EPA a new or 
revised emission limitation that is based on a good engineering practice 
stack height that exceeds the height allowed by Sec. 51.100(ii) (1) or 
(2), the State must notify the public of the availabilty of the 
demonstration study and must provide opportunity for a public hearing on 
it. This section does not require the plan to restrict, in any manner, 
the actual stack height of any source.
    (b) The provisions of Sec. 51.118(a) shall not apply to (1) stack 
heights in existence, or dispersion techniques implemented on or before 
December 31, 1970, except where pollutants are being emitted from such 
stacks or using such dispersion techniques by sources, as defined in 
section 111(a)(3) of the Clean Air Act, which were constructed, or 
reconstructed, or for which major modifications, as defined in 
Sec. Sec. 51.165(a)(1)(v)(A), 51.166(b)(2)(i) and 52.21(b)(2)(i), were 
carried out after December 31, 1970; or (2) coal-fired steam electric 
generating units subject to the provisions of section 118 of the Clean 
Air Act, which commenced operation before July 1, 1957, and whose stacks 
were construced under a construction contract awarded before February 8, 
1974.



Sec. 51.119  Intermittent control systems.

    (a) The use of an intermittent control system (ICS) may be taken 
into account in establishing an emission limitation for a pollutant 
under a State implementation plan, provided:
    (1) The ICS was implemented before December 31, 1970, according to 
the criteria specified in Sec. 51.119(b).
    (2) The extent to which the ICS is taken into account is limited to 
reflect emission levels and associated ambient pollutant concentrations 
that would result if the ICS was the same as it was before December 31, 
1970, and was operated as specified by the operating system of the ICS 
before December 31, 1970.
    (3) The plan allows the ICS to compensate only for emissions from a 
source for which the ICS was implemented before December 31, 1970, and, 
in the event the source has been modified, only to the extent the 
emissions correspond to the maximum capacity of the source before 
December 31, 1970. For purposes of this paragraph, a source for which 
the ICS was implemented is any particular structure or equipment the 
emissions from which were subject to the ICS operating procedures.
    (4) The plan requires the continued operation of any constant 
pollution control system which was in use before December 31, 1970, or 
the equivalent of that system.
    (5) The plan clearly defines the emission limits affected by the ICS 
and the manner in which the ICS is taken into account in establishing 
those limits.
    (6) The plan contains requirements for the operation and maintenance 
of the qualifying ICS which, together with the emission limitations and 
any other necessary requirements, will assure that the national ambient 
air quality standards and any applicable prevention of significant 
deterioration increments will be attained and maintained. These 
requirements shall include, but not necessarily be limited to, the 
following:
    (i) Requirements that a source owner or operator continuously 
operate and maintain the components of the ICS specified at Sec. 
51.119(b)(3) (ii)-(iv) in a manner which assures that the ICS is at 
least as effective as it was before December 31, 1970. The air quality 
monitors and meteorological instrumentation specified at Sec. 51.119(b) 
may be operated by a local authority or other entity provided the source 
has ready access to the data from the monitors and instrumentation.
    (ii) Requirements which specify the circumstances under which, the 
extent to which, and the procedures through which, emissions shall be 
curtailed through the activation of ICS.
    (iii) Requirements for recordkeeping which require the owner or 
operator of the source to keep, for periods of at least 3 years, records 
of measured ambient air quality data, meteorological information 
acquired, and production data relating to those processes affected by 
the ICS.
    (iv) Requirements for reporting which require the owner or operator 
of the source to notify the State and EPA

[[Page 164]]

within 30 days of a NAAQS violation pertaining to the pollutant affected 
by the ICS.
    (7) Nothing in this paragraph affects the applicability of any new 
source review requirements or new source performance standards contained 
in the Clean Air Act or 40 CFR subchapter C. Nothing in this paragraph 
precludes a State from taking an ICS into account in establishing 
emission limitations to any extent less than permitted by this 
paragraph.
    (b) An intermittent control system (ICS) may be considered 
implemented for a pollutant before December 31, 1970, if the following 
criteria are met:
    (1) The ICS must have been established and operational with respect 
to that pollutant prior to December 31, 1970, and reductions in 
emissions of that pollutant must have occurred when warranted by 
meteorological and ambient monitoring data.
    (2) The ICS must have been designed and operated to meet an air 
quality objective for that pollutant such as an air quality level or 
standard.
    (3) The ICS must, at a minimum, have included the following 
components prior to December 31, 1970:
    (i) Air quality monitors. An array of sampling stations whose 
location and type were consistent with the air quality objective and 
operation of the system.
    (ii) Meteorological instrumentation. A meteorological data 
acquisition network (may be limited to a single station) which provided 
meteorological prediction capabilities sufficient to determine the need 
for, and degree of, emission curtailments necessary to achieve the air 
quality design objective.
    (iii) Operating system. A system of established procedures for 
determining the need for curtailments and for accomplishing such 
curtailments. Documentation of this system, as required by paragraph 
(n)(4), may consist of a compendium of memoranda or comparable material 
which define the criteria and procedures for curtailments and which 
identify the type and number of personnel authorized to initiate 
curtailments.
    (iv) Meteorologist. A person, schooled in meteorology, capable of 
interpreting data obtained from the meteorological network and qualified 
to forecast meteorological incidents and their effect on ambient air 
quality. Sources may have obtained meteorological services through a 
consultant. Services of such a consultant could include sufficient 
training of source personnel for certain operational procedures, but not 
for design, of the ICS.
    (4) Documentation sufficient to support the claim that the ICS met 
the criteria listed in this paragraph must be provided. Such 
documentation may include affidavits or other documentation.



Sec. 51.120  Requirements for State Implementation Plan revisions
relating to new motor vehicles.

    (a) The EPA Administrator finds that the State Implementation Plans 
(SIPs) for the States of Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode 
Island, and Vermont, the portion of Virginia included (as of November 
15, 1990) within the Consolidated Metropolitan Statistical Area that 
includes the District of Columbia, are substantially inadequate to 
comply with the requirements of section 110(a)(2)(D) of the Clean Air 
Act, 42 U.S.C. 7410(a)(2)(D), and to mitigate adequately the interstate 
pollutant transport described in section 184 of the Clean Air Act, 42 
U.S.C. 7511C, to the extent that they do not provide for emission 
reductions from new motor vehicles in the amount that would be achieved 
by the Ozone Transport Commission low emission vehicle (OTC LEV) program 
described in paragraph (c) of this section. This inadequacy will be 
deemed cured for each of the aforementioned States (including the 
District of Columbia) in the event that EPA determines through 
rulemaking that a national LEV-equivalent new motor vehicle emission 
control program is an acceptable alternative for OTC LEV and finds that 
such program is in effect. In the event no such finding is made, each of 
those States must adopt and submit to EPA by February 15, 1996 a SIP 
revision meeting the requirements of paragraph (b) of this section in 
order to cure the SIP inadequacy.

[[Page 165]]

    (b) If a SIP revision is required under paragraph (a) of this 
section, it must contain the OTC LEV program described in paragraph (c) 
of this section unless the State adopts and submits to EPA, as a SIP 
revision, other emission-reduction measures sufficient to meet the 
requirements of paragraph (d) of this section. If a State adopts and 
submits to EPA, as a SIP revision, other emission-reduction measures 
pursuant to paragraph (d) of this section, then for purposes of 
determining whether such a SIP revision is complete within the meaning 
of section 110(k)(1) (and hence is eligible at least for consideration 
to be approved as satisfying paragraph (d) of this section), such a SIP 
revision must contain other adopted emission-reduction measures that, 
together with the identified potentially broadly practicable measures, 
achieve at least the minimum level of emission reductions that could 
potentially satisfy the requirements of paragraph (d) of this section. 
All such measures must be fully adopted and enforceable.
    (c) The OTC LEV program is a program adopted pursuant to section 177 
of the Clean Air Act.
    (1) The OTC LEV program shall contain the following elements:
    (i) It shall apply to all new 1999 and later model year passenger 
cars and light-duty trucks (0-5750 pounds loaded vehicle weight), as 
defined in Title 13, California Code of Regulations, section 1900(b)(11) 
and (b)(8), respectively, that are sold, imported, delivered, purchased, 
leased, rented, acquired, received, or registered in any area of the 
State that is in the Northeast Ozone Transport Region as of December 19, 
1994.
    (ii) All vehicles to which the OTC LEV program is applicable shall 
be required to have a certificate from the California Air Resources 
Board (CARB) affirming compliance with California standards.
    (iii) All vehicles to which this LEV program is applicable shall be 
required to meet the mass emission standards for Non-Methane Organic 
Gases (NMOG), Carbon Monoxide (CO), Oxides of Nitrogen (NOX), 
Formaldehyde (HCHO), and particulate matter (PM) as specified in Title 
13, California Code of Regulations, section 1960.1(f)(2) (and 
formaldehyde standards under section 1960.1(e)(2), as applicable) or as 
specified by California for certification as a TLEV (Transitional Low-
Emission Vehicle), LEV (Low-Emission Vehicle), ULEV (Ultra-Low-Emission 
Vehicle), or ZEV (Zero-Emission Vehicle) under section 1960.1(g)(1) (and 
section 1960.1(e)(3), for formaldehyde standards, as applicable).
    (iv) All manufacturers of vehicles subject to the OTC LEV program 
shall be required to meet the fleet average NMOG exhaust emission values 
for production and delivery for sale of their passenger cars, light-duty 
trucks 0-3750 pounds loaded vehicle weight, and light-duty trucks 3751-
5750 pounds loaded vehicle weight specified in Title 13, California Code 
of Regulations, section 1960.1(g)(2) for each model year beginning in 
1999. A State may determine not to implement the NMOG fleet average in 
the first model year of the program if the State begins implementation 
of the program late in a calendar year. However, all States must 
implement the NMOG fleet average in any full model years of the LEV 
program.
    (v) All manufacturers shall be allowed to average, bank and trade 
credits in the same manner as allowed under the program specified in 
Title 13, California Code of Regulations, section 1960.1(g)(2) footnote 
7 for each model year beginning in 1999. States may account for credits 
banked by manufacturers in California or New York in years immediately 
preceding model year 1999, in a manner consistent with California 
banking and discounting procedures.
    (vi) The provisions for small volume manufacturers and intermediate 
volume manufacturers, as applied by Title 13, California Code of 
Regulations to California's LEV program, shall apply. Those 
manufacturers defined as small volume manufacturers and intermediate 
volume manufacturers in California under California's regulations shall 
be considered small volume manufacturers and intermediate volume 
manufacturers under this program.
    (vii) The provisions for hybrid electric vehicles (HEVs), as defined 
in Title 13 California Code of Regulations, section 1960.1, shall apply 
for purposes of calculating fleet average NMOG values.

[[Page 166]]

    (viii) The provisions for fuel-flexible vehicles and dual-fuel 
vehicles specified in Title 13, California Code of Regulations, section 
1960.1(g)(1) footnote 4 shall apply.
    (ix) The provisions for reactivity adjustment factors, as defined by 
Title 13, California Code of Regulations, shall apply.
    (x) The aforementioned State OTC LEV standards shall be identical to 
the aforementioned California standards as such standards exist on 
December 19, 1994.
    (xi) All States' OTC LEV programs must contain any other provisions 
of California's LEV program specified in Title 13, California Code of 
Regulations necessary to comply with section 177 of the Clean Air Act.
    (2) States are not required to include the mandate for production of 
ZEVs specified in Title 13, California Code of Regulations, section 
1960.1(g)(2) footnote 9.
    (3) Except as specified elsewhere in this section, States may 
implement the OTC LEV program in any manner consistent with the Act that 
does not decrease the emissions reductions or jeopardize the 
effectiveness of the program.
    (d) The SIP revision that paragraph (b) of this section describes as 
an alternative to the OTC LEV program described in paragraph (c) of this 
section must contain a set of State-adopted measures that provides at 
least the following amount of emission reductions in time to bring 
serious ozone nonattainment areas into attainment by their 1999 
attainment date:
    (1) Reductions at least equal to the difference between:
    (i) The nitrogen oxides (NOX) emission reductions from 
the 1990 statewide emissions inventory achievable through implementation 
of all of the Clean Air Act-mandated and potentially broadly practicable 
control measures throughout all portions of the State that are within 
the Northeast Ozone Transport Region created under section 184(a) of the 
Clean Air Act as of December 19, 1994; and
    (ii) A reduction in NOX emissions from the 1990 statewide 
inventory in such portions of the State of 50% or whatever greater 
reduction is necessary to prevent significant contribution to 
nonattainment in, or interference with maintenance by, any downwind 
State.
    (2) Reductions at least equal to the difference between:
    (i) The VOC emission reductions from the 1990 statewide emissions 
inventory achievable through implementation of all of the Clean Air Act-
mandated and potentially broadly practicable control measures in all 
portions of the State in, or near and upwind of, any of the serious or 
severe ozone nonattainment areas lying in the series of such areas 
running northeast from the Washington, DC, ozone nonattainment area to 
and including the Portsmouth, New Hampshire ozone nonattainment area; 
and
    (ii) A reduction in VOC emissions from the 1990 emissions inventory 
in all such areas of 50% or whatever greater reduction is necessary to 
prevent significant contribution to nonattainment in, or interference 
with maintenance by, any downwind State.

[60 FR 4736, Jan. 24, 1995]



Sec. 51.121  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of oxides of nitrogen.

    (a)(1) The Administrator finds that the State implementation plan 
(SIP) for each jurisdiction listed in paragraph (c) of this section is 
substantially inadequate to comply with the requirements of section 
110(a)(2)(D)(i)(I) of the Clean Air Act (CAA), 42 U.S.C. 
7410(a)(2)(D)(i)(I), because the SIP does not include adequate 
provisions to prohibit sources and other activities from emitting 
nitrogen oxides (``NOX'') in amounts that will contribute 
significantly to nonattainment in one or more other States with respect 
to the 1-hour ozone national ambient air quality standards (NAAQS). Each 
of the jurisdictions listed in paragraph (c) of this section must submit 
to EPA a SIP revision that cures the inadequacy.
    (2) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each jurisdiction listed in paragraph (c) 
of this section must submit a SIP revision to comply with the 
requirements of section

[[Page 167]]

110(a)(2)(D)(i)(I), 42 U.S.C. 7410(a)(2)(D)(i)(I), through the adoption 
of adequate provisions prohibiting sources and other activities from 
emitting NOX in amounts that will contribute significantly to 
nonattainment in, or interfere with maintenance by, one or more other 
States with respect to the 8-hour ozone NAAQS.
    (3)(i) For purposes of this section, the term ``Phase I SIP 
Submission'' means those SIP revisions submitted by States on or before 
October 30, 2000 in compliance with paragraph (b)(1)(ii) of this 
section. A State's Phase I SIP submission may include portions of the 
NOX budget, under paragraph (e)(3) of this section, that a 
State is required to include in a Phase II SIP submission.
    (ii) For purposes of this section, the term ``Phase II SIP 
Submission'' means those SIP revisions that must be submitted by a State 
in compliance with paragraph (b)(1)(ii) of this section and which 
includes portions of the NOX budget under paragraph (e)(3) of 
this section.
    (b)(1) For each jurisdiction listed in paragraph (c) of this 
section, the SIP revision required under paragraph (a) of this section 
will contain adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision:
    (i) Contains control measures adequate to prohibit emissions of 
NOX that would otherwise be projected, in accordance with 
paragraph (g) of this section, to cause the jurisdiction's overall 
NOX emissions to be in excess of the budget for that 
jurisdiction described in paragraph (e) of this section (except as 
provided in paragraph (b)(2) of this section),
    (ii) Requires full implementation of all such control measures by no 
later than May 31, 2004 for the sources covered by a Phase I SIP 
submission and May 1, 2007 for the sources covered by a Phase II SIP 
submission.
    (iii) Meets the other requirements of this section. The SIP 
revision's compliance with the requirement of paragraph (b)(1)(i) of 
this section shall be considered compliance with the jurisdiction's 
budget for purposes of this section.
    (2) The requirements of paragraph (b)(1)(i) of this section shall be 
deemed satisfied, for the portion of the budget covered by an interstate 
trading program, if the SIP revision:
    (i) Contains provisions for an interstate trading program that EPA 
determines will, in conjunction with interstate trading programs for one 
or more other jurisdictions, prohibit NOX emissions in excess 
of the sum of the portion of the budgets covered by the trading programs 
for those jurisdictions; and
    (ii) Conforms to the following criteria:
    (A) Emissions reductions used to demonstrate compliance with the 
revision must occur during the ozone season.
    (B) Emissions reductions occurring prior to the first year in which 
any sources covered by Phase I or Phase II SIP submission are subject to 
control measures under paragraph (b)(1)(i) of this section may be used 
by a source to demonstrate compliance with the SIP revision for the 
first and second ozone seasons in which any sources covered by a Phase I 
or Phase II SIP submission are subject to such control measures, 
provided the SIPs provisions regarding such use comply with the 
requirements of paragraph (e)(4) of this section.
    (C) Emissions reductions credits or emissions allowances held by a 
source or other person following the first ozone season in which any 
sources covered by a Phase I or Phase II SIP submission are subject to 
control measures under paragraph (b)(1)(i) of this section or any ozone 
season thereafter that are not required to demonstrate compliance with 
the SIP for the relevant ozone season may be banked and used to 
demonstrate compliance with the SIP in a subsequent ozone season.
    (D) Early reductions created according to the provisions in 
paragraph (b)(2)(ii)(B) of this section and used in the first ozone 
season in which any sources covered by Phase I or Phase II submissions 
are subject to the control measures under paragraph (b)(1)(i) of this 
section are not subject to the flow control provisions set forth in 
paragraph (b)(2)(ii)(E) of this section.

[[Page 168]]

    (E) Starting with the second ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section, the SIP shall 
include provisions to limit the use of banked emissions reductions 
credits or emissions allowances beyond a predetermined amount as 
calculated by one of the following approaches:
    (1) Following the determination of compliance after each ozone 
season, if the total number of emissions reduction credits or banked 
allowances held by sources or other persons subject to the trading 
program exceeds 10 percent of the sum of the allowable ozone season 
NOX emissions for all sources subject to the trading program, 
then all banked allowances used for compliance for the following ozone 
season shall be subject to the following:
    (i) A ratio will be established according to the following formula: 
(0.10) x (the sum of the allowable ozone season NOX emissions 
for all sources subject to the trading program) / (the total number of 
banked emissions reduction credits or emissions allowances held by all 
sources or other persons subject to the trading program).
    (ii) The ratio, determined using the formula specified in paragraph 
(b)(2)(ii)(E)(1)(i) of this section, will be multiplied by the number of 
banked emissions reduction credits or emissions allowances held in each 
account at the time of compliance determination. The resulting product 
is the number of banked emissions reduction credits or emissions 
allowances in the account which can be used in the current year's ozone 
season at a rate of 1 credit or allowance for every 1 ton of emissions. 
The SIP shall specify that banked emissions reduction credits or 
emissions allowances in excess of the resulting product either may not 
be used for compliance, or may only be used for compliance at a rate no 
less than 2 credits or allowances for every 1 ton of emissions.
    (2) At the time of compliance determination for each ozone season, 
if the total number of banked emissions reduction credits or emissions 
allowances held by a source subject to the trading program exceeds 10 
percent of the source's allowable ozone season NOX emissions, 
all banked emissions reduction credits or emissions allowances used for 
compliance in such ozone season by the source shall be subject to the 
following:
    (i) The source may use an amount of banked emissions reduction 
credits or emissions allowances not greater than 10 percent of the 
source's allowable ozone season NOX emissions for compliance 
at a rate of 1 credit or allowance for every 1 ton of emissions.
    (ii) The SIP shall specify that banked emissions reduction credits 
or emissions allowances in excess of 10 percent of the source's 
allowable ozone season NOX emissions may not be used for 
compliance, or may only be used for compliance at a rate no less than 2 
credits or allowances for every 1 ton of emissions.
    (c) The following jurisdictions (hereinafter referred to as 
``States'') are subject to the requirement of this section:
    (1) With respect to the 1-hour ozone NAAQS: Connecticut, Delaware, 
Illinois, Indiana, Kentucky, Maryland, Massachusetts, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, 
Tennessee, Virginia, West Virginia, and the District of Columbia.
    (2) With respect to the 1-hour ozone NAAQS, the portions of 
Missouri, Michigan, and Alabama within the fine grid of the OTAG 
modeling domain. The fine grid is the area encompassed by a box with the 
following geographic coordinates: Southwest Corner, 92 degrees West 
longitude and 32 degrees North latitude; and Northeast Corner, 69.5 
degrees West longitude and 44 degrees North latitude.
    (d)(1) The SIP submissions required under paragraph (a) of this 
section must be submitted to EPA by no later than October 30, 2000 for 
Phase I SIP submissions and no later than April 1, 2005 for Phase II SIP 
submissions.
    (2) The State makes an official submission of its SIP revision to 
EPA only when:
    (i) The submission conforms to the requirements of appendix V to 
this part; and
    (ii) The State delivers five copies of the plan to the appropriate 
Regional

[[Page 169]]

Office, with a letter giving notice of such action.
    (e)(1) Except as provided in paragraph (e)(2)(ii) of this section, 
the NOX budget for a State listed in paragraph (c) of this 
section is defined as the total amount of NOX emissions from 
all sources in that State, as indicated in paragraph (e)(2)(i) of this 
section with respect to that State, which the State must demonstrate 
that it will not exceed in the 2007 ozone season pursuant to paragraph 
(g)(1) of this section.
    (2)(i) The State-by-State amounts of the NOX budget, 
expressed in tons, are as follows:

------------------------------------------------------------------------
                      State                          Final budget   Budget
------------------------------------------------------------------ --------
Alabama..........................................          119,827
Connecticut......................................           42,850
Delaware.........................................           22,862
District of Columbia.............................            6,657
Illinois.........................................          271,091
Indiana..........................................          230,381
Kentucky.........................................          162,519
Maryland.........................................           81,947
Massachusetts....................................           84,848
Michigan.........................................          190,908
Missouri.........................................           61,406
New Jersey.......................................           96,876
New York.........................................          240,322
North Carolina...................................          165,306
Ohio.............................................          249,541
Pennsylvania.....................................          257,928
Rhode Island.....................................            9,378
South Carolina...................................          123,496
Tennessee........................................          198,286
Virginia.........................................          180,521
West Virginia....................................           83,921
                                                  ------------------
  Total..........................................       $3,031,527
------------------------------------------------------------------------

    (ii) (A) For purposes of paragraph (e)(2)(i) of this section, in the 
case of each State listed in paragraphs (e)(2)(ii)(B) through (E) of 
this section, the NOX budget is defined as the total amount 
of NOX emissions from all sources in the specified counties 
in that State, as indicated in paragraph (e)(2)(i) of this section with 
respect to the State, which the State must demonstrate that it will not 
exceed in the 2007 ozone season pursuant to paragraph (g)(1) of this 
section.
    (B) In the case of Alabama, the counties are: Autauga, Bibb, Blount, 
Calhoun, Chambers, Cherokee, Chilton, Clay, Cleburne, Colbert, Coosa, 
Cullman, Dallas, De Kalb, Elmore, Etowah, Fayette, Franklin, Greene, 
Hale, Jackson, Jefferson, Lamar, Lauderdale, Lawrence, Lee, Limestone, 
Macon, Madison, Marion, Marshall, Morgan, Perry, Pickens, Randolph, 
Russell, St. Clair, Shelby, Sumter, Talladega, Tallapoosa, Tuscaloosa, 
Walker, and Winston.
    (C) [Reserved]
    (D) In the case of Michigan, the counties are: Allegan, Barry, Bay, 
Berrien, Branch, Calhoun, Cass, Clinton, Eaton, Genesee, Gratiot, 
Hillsdale, Ingham, Ionia, Isabella, Jackson, Kalamazoo, Kent, Lapeer, 
Lenawee, Livingston, Macomb, Mecosta, Midland, Monroe, Montcalm, 
Muskegon, Newaygo, Oakland, Oceana, Ottawa, Saginaw, St. Clair, St. 
Joseph, Sanilac, Shiawassee, Tuscola, Van Buren, Washtenaw, and Wayne.
    (E) In the case of Missouri, the counties are: Bollinger, Butler, 
Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Franklin, 
Gasconade, Iron, Jefferson, Lewis, Lincoln, Madison, Marion, 
Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Pike, 
Ralls, Reynolds, Ripley, St. Charles, St. Genevieve, St. Francois, St. 
Louis, St. Louis City, Scott, Shannon, Stoddard, Warren, Washington, and 
Wayne.
    (3) The State-by-State amounts of the portion of the NOX 
budget provided in paragraph (e)(1) of this section, expressed in tons, 
that the States may include in a Phase II SIP submission are as follows:

------------------------------------------------------------------------
                                                             Phase II
                         State                             incremental
                                                              budget
------------------------------------------------------------------------
Alabama................................................            4,968
Connecticut............................................               41
Delaware...............................................              660
District of Columbia...................................                1
Illinois...............................................            7,055
Indiana................................................            4,244
Kentucky...............................................            2,556
Maryland...............................................              780
Massachusetts..........................................            1,023
Michigan...............................................            1,033
New Jersey.............................................             -994
New York...............................................            1,659
North Carolina.........................................            6,026
Ohio...................................................            2,741
Pennsylvania...........................................           10,230
Rhode Island...........................................              192
South Carolina.........................................            4,260
Tennessee..............................................            2,877
Virginia...............................................            6,168
West Virginia..........................................            1,124
                                                        ----------------
    Total..............................................           56,644
------------------------------------------------------------------------

    (4)(i) Notwithstanding the State's obligation to comply with the 
budgets set forth in paragraph (e)(2) of this section,

[[Page 170]]

a SIP revision may allow sources required by the revision to implement 
NOX emission control measures to demonstrate compliance in 
the first and second ozone seasons in which any sources covered by a 
Phase I or Phase II SIP submission are subject to control measures under 
paragraph (b)(1)(i) of this section using credit issued from the State's 
compliance supplement pool, as set forth in paragraph (e)(4)(iii) of 
this section.
    (ii) A source may not use credit from the compliance supplement pool 
to demonstrate compliance after the second ozone season in which any 
sources are covered by a Phase I or Phase II SIP submission.
    (iii) The State-by-State amounts of the compliance supplement pool 
are as follows:

------------------------------------------------------------------------
                                                            Compliance
                         State                           supplement pool
                                                           (tons of NOX)
------------------------------------------------------------------------
Alabama................................................            8,962
Connecticut............................................              569
Delaware...............................................              168
District of Columbia...................................                0
Illinois...............................................           17,688
Indiana................................................           19,915
Kentucky...............................................           13,520
Maryland...............................................            3,882
Massachusetts..........................................              404
Michigan...............................................            9,907
Missouri...............................................            5,630
New Jersey.............................................            1,550
New York...............................................            2,764
North Carolina.........................................           10,737
Ohio...................................................           22,301
Pennsylvania...........................................           15,763
Rhode Island...........................................               15
South Carolina.........................................            5,344
Tennessee..............................................           10,565
Virginia...............................................            5,504
West Virginia..........................................           16,709
                                                        ----------------
  Total................................................          182,625
------------------------------------------------------------------------

    (iv) The SIP revision may provide for the distribution of the 
compliance supplement pool to sources that are required to implement 
control measures using one or both of the following two mechanisms:
    (A) The State may issue some or all of the compliance supplement 
pool to sources that implement emissions reductions during the ozone 
season beyond all applicable requirements in the first ozone season in 
which any sources covered by a Phase I or Phase II SIP submission are 
subject to control measures under paragraph (b)(1)(i) of this section.
    (1) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
    (2) The emissions reduction may not be required by the State's SIP 
or be otherwise required by the CAA.
    (3) The emissions reductions must be verified by the source as 
actually having occurred during an ozone season between September 30, 
1999 and the commencement of the first ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section.
    (4) The emissions reduction must be quantified according to 
procedures set forth in the SIP revision and approved by EPA. Emissions 
reductions implemented by sources serving electric generators with a 
nameplate capacity greater than 25 MWe, or boilers, combustion turbines 
or combined cycle units with a maximum design heat input greater than 
250 mmBtu/hr, must be quantified according to the requirements in 
paragraph (i)(4) of this section.
    (5) If the SIP revision contains approved provisions for an 
emissions trading program, sources that receive credit according to the 
requirements of this paragraph may trade the credit to other sources or 
persons according to the provisions in the trading program.
    (B) The State may issue some or all of the compliance supplement 
pool to sources that demonstrate a need for an extension of the earliest 
date on which any sources covered by a Phase I or Phase II SIP 
submission are subject to control measures under paragraph (b)(1)(i) of 
this section according to the following provisions:
    (1) The State shall initiate the issuance process by the later date 
of September 30 before the first ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section or after the State 
issues credit according

[[Page 171]]

to the procedures in paragraph (e)(4)(iv)(A) of this section.
    (2) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
    (3) The State shall issue credit to a source only if the source 
demonstrates the following:
    (i) For a source used to generate electricity, compliance with the 
SIP revision's applicable control measures by the commencement of the 
first ozone season in which any sources covered by a Phase I or Phase II 
SIP submission are subject to control measures under paragraph (b)(1)(i) 
of this section, would create undue risk for the reliability of the 
electricity supply. This demonstration must include a showing that it 
would not be feasible to import electricity from other electricity 
generation systems during the installation of control technologies 
necessary to comply with the SIP revision.
    (ii) For a source not used to generate electricity, compliance with 
the SIP revision's applicable control measures by the commencement of 
the first ozone season in which any sources covered by a Phase I or 
Phase II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section would create undue risk for the source or its 
associated industry to a degree that is comparable to the risk described 
in paragraph (e)(4)(iv)(B)(3)(i) of this section.
    (iii) For a source subject to an approved SIP revision that allows 
for early reduction credits in accordance with paragraph (e)(4)(iv)(A) 
of this section, it was not possible for the source to comply with 
applicable control measures by generating early reduction credits or 
acquiring early reduction credits from other sources.
    (iv) For a source subject to an approved emissions trading program, 
it was not possible to comply with applicable control measures by 
acquiring sufficient credit from other sources or persons subject to the 
emissions trading program.
    (4) The State shall ensure the public an opportunity, through a 
public hearing process, to comment on the appropriateness of allocating 
compliance supplement pool credits to a source under paragraph 
(e)(3)(iv)(B) of this section.
    (5) If, no later than February 22, 1999, any member of the public 
requests revisions to the source-specific data and vehicle miles 
traveled (VMT) and nonroad mobile growth rates, VMT distribution by 
vehicle class, average speed by roadway type, inspection and maintenance 
program parameters, and other input parameters used to establish the 
State budgets set forth in paragraph (e)(2) of this section or the 2007 
baseline sub-inventory information set forth in paragraph (g)(2)(ii) of 
this section, then EPA will act on that request no later than April 23, 
1999 provided:
    (i) The request is submitted in electronic format;
    (ii) Information is provided to corroborate and justify the need for 
the requested modification;
    (iii) The request includes the following data information regarding 
any electricity-generating source at issue:
    (A) Federal Information Placement System (FIPS) State Code;
    (B) FIPS County Code;
    (C) Plant name;
    (D) Plant ID numbers (ORIS code preferred, State agency tracking 
number also or otherwise);
    (E) Unit ID numbers (a unit is a boiler or other combustion device);
    (F) Unit type;
    (G) Primary fuel on a heat input basis;
    (H) Maximum rated heat input capacity of unit;
    (I) Nameplate capacity of the largest generator the unit serves;
    (J) Ozone season heat inputs for the years 1995 and 1996;
    (K) 1996 (or most recent) average NOX rate for the ozone 
season;
    (L) Latitude and longitude coordinates;
    (M) Stack parameter information ;
    (N) Operating parameter information;
    (O) Identification of specific change to the inventory; and
    (P) Reason for the change;
    (iv) The request includes the following data information regarding 
any

[[Page 172]]

non-electricity generating point source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Plant name;
    (D) Facility primary standard industrial classification code (SIC);
    (E) Plant ID numbers (NEDS, AIRS/AFS, and State agency tracking 
number also or otherwise);
    (F) Unit ID numbers (a unit is a boiler or other combustion device);
    (G) Primary source classification code (SCC);
    (H) Maximum rated heat input capacity of unit;
    (I) 1995 ozone season or typical ozone season daily NOX 
emissions;
    (J) 1995 existing NOX control efficiency;
    (K) Latitude and longitude coordinates;
    (L) Stack parameter information;
    (M) Operating parameter information;
    (N) Identification of specific change to the inventory; and
    (O) Reason for the change;
    (v) The request includes the following data information regarding 
any stationary area source or nonroad mobile source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Primary source classification code (SCC);
    (D) 1995 ozone season or typical ozone season daily NOX 
emissions;
    (E) 1995 existing NOX control efficiency;
    (F) Identification of specific change to the inventory; and
    (G) Reason for the change;
    (vi) The request includes the following data information regarding 
any highway mobile source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Primary source classification code (SCC) or vehicle type;
    (D) 1995 ozone season or typical ozone season daily vehicle miles 
traveled (VMT);
    (E) 1995 existing NOX control programs;
    (F) identification of specific change to the inventory; and
    (G) reason for the change.
    (f) Each SIP revision must set forth control measures to meet the 
NOX budget in accordance with paragraph (b)(1)(i) of this 
section, which include the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2) Should a State elect to impose control measures on fossil fuel-
fired NOX sources serving electric generators with a 
nameplate capacity greater than 25 MWe or boilers, combustion turbines 
or combined cycle units with a maximum design heat input greater than 
250 mmBtu/hr as a means of meeting its NOX budget, then those 
measures must:
    (i)(A) Impose a NOX mass emissions cap on each source;
    (B) Impose a NOX emissions rate limit on each source and 
assume maximum operating capacity for every such source for purposes of 
estimating mass NOX emissions; or
    (C) Impose any other regulatory requirement which the State has 
demonstrated to EPA provides equivalent or greater assurance than 
options in paragraphs (f)(2)(i)(A) or (f)(2)(i)(B) of this section that 
the State will comply with its NOX budget in the 2007 ozone 
season; and
    (ii) Impose enforceable mechanisms, in accordance with paragraphs 
(b)(1) (i) and (ii) of this section, to assure that collectively all 
such sources, including new or modified units, will not exceed in the 
2007 ozone season the total NOX emissions projected for such 
sources by the State pursuant to paragraph (g) of this section.
    (3) For purposes of paragraph (f)(2) of this section, the term 
``fossil fuel-fired'' means, with regard to a NOX source:
    (i) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year starting 
in 1995 or, if a NOX source had no heat input starting

[[Page 173]]

in 1995, during the last year of operation of the NOX source 
prior to 1995; or
    (ii) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year; 
provided that the NOX source shall be ``fossil fuel-fired'' 
as of the date, during such year, on which the NOX source 
begins combusting fossil fuel.
    (g)(1) Each SIP revision must demonstrate that the control measures 
contained in it are adequate to provide for the timely compliance with 
the State's NOX budget during the 2007 ozone season.
    (2) The demonstration must include the following:
    (i) Each revision must contain a detailed baseline inventory of 
NOX mass emissions from the following sources in the year 
2007, absent the control measures specified in the SIP submission: 
electric generating units (EGU), non-electric generating units (non-
EGU), area, nonroad and highway sources. The State must use the same 
baseline emissions inventory that EPA used in calculating the State's 
NOX budget, as set forth for the State in paragraph 
(g)(2)(ii) of this section, except that EPA may direct the State to use 
different baseline inventory information if the State fails to certify 
that it has implemented all of the control measures assumed in 
developing the baseline inventory.
    (ii) The revised NOX emissions sub-inventories for each 
State, expressed in tons per ozone season, are as follows:

----------------------------------------------------------------------------------------------------------------
                     State                          EGU      Non-EGU    Area     Nonroad    Highway      Total
----------------------------------------------------------------------------------------------------------------
Alabama.......................................      29,022    43,415    28,762    20,146      51,274     172,619
Connecticut...................................       2,652     5,216     4,821    10,736      19,424      42,849
Delaware......................................       5,250     2,473     1,129     5,651       8,358      22,861
District of Columbia..........................         207       282       830     3,135       2,204       6,658
Illinois......................................      32,372    59,577     9,369    56,724     112,518     270,560
Indiana.......................................      47,731    47,363    29,070    26,494      79,307     229,965
Kentucky......................................      36,503    25,669    31,807    15,025      53,268     162,272
Maryland......................................      14,656    12,585     4,448    20,026      30,183      81,898
Massachusetts.................................      15,146    10,298    11,048    20,166      28,190      84,848
Michigan......................................      32,228    60,055    31,721    26,935      78,763     229,702
Missouri......................................      24,216    21,602     7,341    20,829      51,615     125,603
New Jersey....................................      10,250    15,464    12,431    23,565      35,166      96,876
New York......................................      31,036    25,477    17,423    42,091     124,261     240,288
North Carolina................................      31,821    26,434    11,067    22,005      73,695     165,022
Ohio..........................................      48,990    40,194    21,860    43,380      94,850     249,274
Pennsylvania..................................      47,469    70,132    17,842    30,571      91,578     257,592
Rhode Island..................................         997     1,635       448     2,455       3,843       9,378
South Carolina................................      16,772    27,787     9,415    14,637      54,494     123,105
Tennessee.....................................      25,814    39,636    13,333    52,920      66,342     198,045
Virginia......................................      17,187    35,216    27,738    27,859      72,195     180,195
West Virginia.................................      26,859    20,238     5,459    10,433      20,844      83,833
Wisconsin.....................................      17,381    19,853    11,253    17,965      69,319     135,771
                                               -----------------------------------------------------------------
    Total.....................................     544,961   640,317   321,827   540,215   1,310,466  3,357,786
----------------------------------------------------------------------------------------------------------------
Note to paragraph (g)(2)(ii): Totals may not sum due to rounding.

    (iii) Each revision must contain a summary of NOX mass 
emissions in 2007 projected to result from implementation of each of the 
control measures specified in the SIP submission and from all 
NOX sources together following implementation of all such 
control measures, compared to the baseline 2007 NOX emissions 
inventory for the State described in paragraph (g)(2)(i) of this 
section. The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2007 NOX emissions that will be achieved from the 
implementation of the new control measures compared to the baseline 
emissions inventory.
    (iv) Each revision must identify the sources of the data used in the 
projection of emissions.

[[Page 174]]

    (h) Each revision must comply with Sec. 51.116 of this part 
(regarding data availability).
    (i) Each revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the NOX 
budget. Specifically, the revision must meet the following requirements:
    (1) The revision must provide for legally enforceable procedures for 
requiring owners or operators of stationary sources to maintain records 
of and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The revision must comply with Sec. 51.212 of this part 
(regarding testing, inspection, enforcement, and complaints);
    (3) If the revision contains any transportation control measures, 
then the revision must comply with Sec. 51.213 of this part (regarding 
transportation control measures);
    (4) If the revision contains measures to control fossil fuel-fired 
NOX sources serving electric generators with a nameplate 
capacity greater than 25 MWe or boilers, combustion turbines or combined 
cycle units with a maximum design heat input greater than 250 mmBtu/hr, 
then the revision must require such sources to comply with the 
monitoring provisions of part 75, subpart H.
    (5) For purposes of paragraph (i)(4) of this section, the term 
``fossil fuel-fired'' means, with regard to a NOX source:
    (i) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year starting 
in 1995 or, if a NOX source had no heat input starting in 
1995, during the last year of operation of the NOX source 
prior to 1995; or
    (ii) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year, 
provided that the NOX source shall be ``fossil fuel-fired'' 
as of the date, during such year, on which the NOX source 
begins combusting fossil fuel.
    (j) Each revision must show that the State has legal authority to 
carry out the revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's NOX 
budget specified in paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards, and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources;
    (4) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; also authority for the State to make such data 
available to the public as reported and as correlated with any 
applicable emissions standards or limitations.
    (k)(1) The provisions of law or regulation which the State 
determines provide the authorities required under this section must be 
specifically identified, and copies of such laws or regulations must be 
submitted with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (l)(1) A revision may assign legal authority to local agencies in 
accordance with Sec. 51.232 of this part.
    (2) Each revision must comply with Sec. 51.240 of this part 
(regarding general plan requirements).
    (m) Each revision must comply with Sec. 51.280 of this part 
(regarding resources).
    (n) For purposes of the SIP revisions required by this section, EPA 
may

[[Page 175]]

make a finding as applicable under section 179(a)(1)-(4) of the CAA, 42 
U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth in 
section 179(a) of the CAA. Any such finding will be deemed a finding 
under Sec. 52.31(c) of this part and sanctions will be imposed in 
accordance with the order of sanctions and the terms for such sanctions 
established in Sec. 52.31 of this part.
    (o) Each revision must provide for State compliance with the 
reporting requirements set forth in Sec. 51.122 of this part.
    (p)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to 40 CFR part 96 (the 
model NOX budget trading program for SIPs), incorporates such 
part by reference into its regulations, or adopts regulations that 
differ substantively from such part only as set forth in paragraph 
(p)(2) of this section, then that portion of the State's SIP revision is 
automatically approved as satisfying the same portion of the State's 
NOX emission reduction obligations as the State projects such 
regulations will satisfy, provided that:
    (i) The State has the legal authority to take such action and to 
implement its responsibilities under such regulations, and
    (ii) The SIP revision accurately reflects the NOX 
emissions reductions to be expected from the State's implementation of 
such regulations.
    (2) If a State adopts an emissions trading program that differs 
substantively from 40 CFR part 96 in only the following respects, then 
such portion of the State's SIP revision is approved as set forth in 
paragraph (p)(1) of this section:
    (i) The State may expand the applicability provisions of the trading 
program to include units (as defined in 40 CFR 96.2) that are smaller 
than the size criteria thresholds set forth in 40 CFR 96.4(a);
    (ii) The State may decline to adopt the exemption provisions set 
forth in 40 CFR 96.4(b);
    (iii) The State may decline to adopt the opt-in provisions set forth 
in subpart I of 40 CFR part 96;
    (iv) The State may decline to adopt the allocation provisions set 
forth in subpart E of 40 CFR part 96 and may instead adopt any 
methodology for allocating NOX allowances to individual 
sources, provided that:
    (A) The State's methodology does not allow the State to allocate 
NOX allowances in excess of the total amount of 
NOX emissions which the State has assigned to its trading 
program; and
    (B) The State's methodology conforms with the timing requirements 
for submission of allocations to the Administrator set forth in 40 CFR 
96.41; and
    (v) The State may decline to adopt the early reduction credit 
provisions set forth in 40 CFR 96.55(c) and may instead adopt any 
methodology for issuing credit from the State's compliance supplement 
pool that complies with paragraph (e)(3) of this section.
    (3) If a State adopts an emissions trading program that differs 
substantively from 40 CFR part 96 other than as set forth in paragraph 
(p)(2) of this section, then such portion of the State's SIP revision is 
not automatically approved as set forth in paragraph (p)(1) of this 
section but will be reviewed by the Administrator for approvability in 
accordance with the other provisions of this section.
    (q) Stay of Findings of Significant Contribution with respect to the 
8-hour standard. Notwithstanding any other provisions of this subpart, 
the effectiveness of paragraph (a)(2) of this section is stayed.
    (r)(1) Notwithstanding any provisions of paragraph (p) of this 
section, subparts A through I of part 96 of this chapter, and any 
State's SIP to the contrary, the Administrator will not carry out any of 
the functions set forth for the Administrator in subparts A through I of 
part 96 of this chapter, or in any emissions trading program in a 
State's SIP approved under paragraph (p) of this section, with regard to 
any ozone season that occurs after September 30, 2008.
    (2) Except as provided in Sec. 51.123(bb), a State whose SIP is 
approved as meeting the requirements of this section and that includes 
an emissions trading program approved under paragraph (p) of this 
section must revise the SIP to adopt control measures that satisfy the

[[Page 176]]

same portion of the State's NOX emission reduction 
requirements under this section as the State projected such emissions 
trading program would satisfy.

[63 FR 57491, Oct. 27, 1998, as amended at 63 FR 71225, Dec. 24, 1998; 
64 FR 26305, May 14, 1999; 65 FR 11230, Mar. 2, 2000; 65 FR 56251, Sept. 
18, 2000; 69 FR 21642, Apr. 21, 2004; 70 FR 25317, May 12, 2005; 70 FR 
51597, Aug. 31, 2005; 73 FR 21538, Apr. 22, 2008]



Sec. 51.122  Emissions reporting requirements for SIP revisions relating
to budgets for NOx emissions.

    (a) As used in this section, words and terms shall have the meanings 
set forth in Sec. 51.50.
    (b) For its transport SIP revision under Sec. 51.121, each state 
must submit to EPA NOX emissions data as described in this 
section.
    (c) Each revision must provide for periodic reporting by the state 
of NOX emissions data to demonstrate whether the state's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) For the every-year reporting cycle, each revision must provide 
for reporting of NOX emissions data every year as follows:
    (i) The state must report to EPA emissions data from all 
NOX sources within the state for which the state specified 
control measures in its SIP submission under Sec. 51.121(g), including 
all sources for which the state has adopted measures that differ from 
the measures incorporated into the baseline inventory for the year 2007 
that the state developed in accordance with Sec. 51.121(g).
    (ii) If sources report NOX emissions data to EPA for a 
given year pursuant to a trading program approved under Sec. 51.121(p) 
or pursuant to the monitoring and reporting requirements of 40 CFR part 
75, then the state need not provide an every-year cycle report to EPA 
for such sources.
    (2) For the three-year cycle reporting, each plan must provide for 
triennial (i.e., every third year) reporting of NOX emissions 
data from all sources within the state.
    (3) The data availability requirements in Sec. 51.116 must be 
followed for all data submitted to meet the requirements of paragraphs 
(b)(1) and (2) of this section.
    (d) The data reported in paragraph (b) of this section must meet the 
requirements of subpart A of this part.
    (e) Approval of ozone season calculation by EPA. Each state must 
submit for EPA approval an example of the calculation procedure used to 
calculate ozone season emissions along with sufficient information to 
verify the calculated value of ozone season emissions.
    (f) Reporting schedules.
    (1) Data collection is to begin during the ozone season 1 year prior 
to the state's NOX SIP Call compliance date.
    (2) Reports are to be submitted according to paragraph (b) of this 
section.
    (3) Through 2011, reports are to be submitted according to the 
schedule in Table 1 of this paragraph. After 2011, triennial reports are 
to be submitted every third year and annual reports are to be submitted 
each year that a triennial report is not required.

                Table 1--Schedule for Submitting Reports
------------------------------------------------------------------------
           Data collection year               Type of  report required
------------------------------------------------------------------------
2005......................................  Triennial.
2006......................................  Annual.
2007......................................  Annual.
2008......................................  Triennial.
2009......................................  Annual.
2010......................................  Annual.
2011......................................  Triennial.
------------------------------------------------------------------------

    (4) States must submit data for a required year within the time 
specified after the end of the inventory year for which the data are 
collected. The first inventory (the 2009 inventory year) and all 
subsequent years will be due 12 months following the end of the 
inventory year, i.e., the 2009 inventory must be reported to EPA by 
December 31, 2010.
    (g) Data reporting procedures are given in subpart A. When 
submitting a formal NOX Budget Emissions Report and 
associated data, states shall notify the appropriate EPA Regional 
Office.

[73 FR 76558, Dec. 17, 2008]

[[Page 177]]



Sec. 51.123  Findings and requirements for submission of State implementation
plan revisions relating to emissions of oxides of nitrogen pursuant to the Clean 

          Air Interstate Rule.

    (a)(1) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c)(1) 
and (2) of this section must submit a SIP revision to comply with the 
requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NOX in 
amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the fine particles (PM2.5) NAAQS.
    (2)(a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c)(1) 
and (3) of this section must submit a SIP revision to comply with the 
requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NOX in 
amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the 8-hour ozone NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) of this section will contain 
adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision contains control measures that assure compliance with 
the applicable requirements of this section.
    (c) In addition to being subject to the requirements in paragraphs 
(b) and (d) of this section:
    (1) Alabama, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky, 
Louisiana, Maryland, Michigan, Mississippi, Missouri, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Virginia, West Virginia, Wisconsin, and the District of Columbia shall 
be subject to the requirements contained in paragraphs (e) through (cc) 
of this section;
    (2) Georgia, Minnesota, and Texas shall be subject to the 
requirements in paragraphs (e) through (o) and (cc) of this section; and
    (3) Arkansas, Connecticut, and Massachusetts shall be subject to the 
requirements contained in paragraphs (q) through (cc) of this section.
    (d)(1) The State's SIP revision under paragraph (a) of this section 
must be submitted to EPA by no later than September 11, 2006.
    (2) The requirements of appendix V to this part shall apply to the 
SIP revision under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision under 
paragraph (a) of this section to the appropriate Regional Office, with a 
letter giving notice of such action.
    (e) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Annual 
EGU NOX Budget, if applicable, and achieve the State's Annual 
Non-EGU NOX Reduction Requirement, if applicable, for the 
appropriate periods. The amounts of the State's Annual EGU 
NOX Budget and Annual Non-EGU NOX Reduction 
Requirement shall be determined as follows:
    (1)(i) The Annual EGU NOX Budget for the State is defined 
as the total amount of NOX emissions from all EGUs in that 
State for a year, if the State meets the requirements of paragraph 
(a)(1) of this section by imposing control measures, at least in part, 
on EGUs. If the State imposes control measures under this section on 
only EGUs, the Annual EGU NOX Budget for the State shall not 
exceed the amount, during the indicated periods, specified in paragraph 
(e)(2) of this section.
    (ii) The Annual Non-EGU NOX Reduction Requirement, if 
applicable, is defined as the total amount of NOX emission 
reductions that the State demonstrates, in accordance with paragraph (g) 
of this section, it will achieve from non-EGUs during the appropriate 
period. If the State meets the requirements of paragraph (a)(1) of this 
section by imposing control measures on only non-EGUs, then the State's 
Annual Non-EGU NOX Reduction Requirement shall equal or 
exceed, during the

[[Page 178]]

appropriate periods, the amount determined in accordance with paragraph 
(e)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a)(1) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Annual Non-EGU NOX Reduction Requirement shall 
equal or exceed the difference between the amount specified in paragraph 
(e)(2) of this section for the appropriate period and the amount of the 
State's Annual EGU NOX Budget specified in the SIP revision 
for the appropriate period; and
    (B) The Annual EGU NOX Budget shall not exceed, during 
the indicated periods, the amount specified in paragraph (e)(2) of this 
section plus the amount of the Annual Non-EGU NOX Reduction 
Requirement under paragraph (e)(1)(iii)(A) of this section for the 
appropriate period.
    (2) For a State that complies with the requirements of paragraph 
(a)(1) of this section by imposing control measures on only EGUs, the 
amount of the Annual EGU NOX Budget, in tons of 
NOX per year, shall be as follows, for the indicated State 
for the indicated period:

------------------------------------------------------------------------
                                                          Annual EGU NOX
                                          Annual EGU NOX    budget for
                  State                     budget for       2015 and
                                             2009-2014      thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          69,020          57,517
Delaware................................           4,166           3,472
District of Columbia....................             144             120
Florida.................................          99,445          82,871
Georgia.................................          66,321          55,268
Illinois................................          76,230          63,525
Indiana.................................         108,935          90,779
Iowa....................................          32,692          27,243
Kentucky................................          83,205          69,337
Louisiana...............................          35,512          29,593
Maryland................................          27,724          23,104
Michigan................................          65,304          54,420
Minnesota...............................          31,443          26,203
Mississippi.............................          17,807          14,839
Missouri................................          59,871          49,892
New Jersey..............................          12,670          10,558
New York................................          45,617          38,014
North Carolina..........................          62,183          51,819
Ohio....................................         108,667          90,556
Pennsylvania............................          99,049          82,541
South Carolina..........................          32,662          27,219
Tennessee...............................          50,973          42,478
Texas...................................         181,014         150,845
Virginia................................          36,074          30,062
West Virginia...........................          74,220          61,850
Wisconsin...............................          40,759          33,966
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph 
(a)(1) of this section by imposing control measures on only non-EGUs, 
the amount of the Annual Non-EGU NOX Reduction Requirement, 
in tons of NOX per year, shall be determined, for the State 
for 2009 and thereafter, by subtracting the amount of the State's Annual 
EGU NOX Budget for the appropriate year, specified in 
paragraph (e)(2) of this section from the amount of the State's 
NOX baseline EGU emissions inventory projected for the 
appropriate year, specified in Table 5 of ``Regional and State 
SO2 and NOX Budgets'', March 2005 (available at 
http://www.epa.gov/cleanairinterstaterule).
    (4)(i) Notwithstanding the State's obligation to comply with 
paragraph (e)(2) or (3) of this section, the State's SIP revision may 
allow sources required by the revision to implement control measures to 
demonstrate compliance using credit issued from the State's compliance 
supplement pool, as set forth in paragraph (e)(4)(ii) of this section.
    (ii) The State-by-State amounts of the compliance supplement pool 
are as follows:

------------------------------------------------------------------------
                                                            Compliance
                          State                             supplement
                                                               pool
------------------------------------------------------------------------
Alabama.................................................          10,166
Delaware................................................             843
District of Columbia....................................               0
Florida.................................................           8,335
Georgia.................................................          12,397
Illinois................................................          11,299
Indiana.................................................          20,155
Iowa....................................................           6,978
Kentucky................................................          14,935
Louisiana...............................................           2,251
Maryland................................................           4,670
Michigan................................................           8,347
Minnesota...............................................           6,528
Mississippi.............................................           3,066
Missouri................................................           9,044
New Jersey..............................................             660
New York................................................               0
North Carolina..........................................               0
Ohio....................................................          25,037
Pennsylvania............................................          16,009
South Carolina..........................................           2,600
Tennessee...............................................           8,944
Texas...................................................             772
Virginia................................................           5,134
West Virginia...........................................          16,929
Wisconsin...............................................           4,898
------------------------------------------------------------------------

    (iii) The SIP revision may provide for the distribution of credits 
from the compliance supplement pool to sources that are required to 
implement control measures using one or both of the following two 
mechanisms:

[[Page 179]]

    (A) The State may issue credit from compliance supplement pool to 
sources that are required by the SIP revision to implement 
NOX emission control measures and that implement 
NOX emission reductions in 2007 and 2008 that are not 
necessary to comply with any State or federal emissions limitation 
applicable at any time during such years. Such a source may be issued 
one credit from the compliance supplement pool for each ton of such 
emission reductions in 2007 and 2008.
    (1) The State shall complete the issuance process by January 1, 
2010.
    (2) The emissions reductions for which credits are issued must have 
been demonstrated by the owners and operators of the source to have 
occurred during 2007 and 2008 and not to be necessary to comply with any 
applicable State or federal emissions limitation.
    (3) The emissions reductions for which credits are issued must have 
been quantified by the owners and operators of the source:
    (i) For EGUs and for fossil-fuel-fired non-EGUs that are boilers or 
combustion turbines with a maximum design heat input greater than 250 
mmBut/hr, using emissions data determined in accordance with subpart H 
of part 75 of this chapter; and
    (ii) For non-EGUs not described in paragraph (e)(4)(iii)(A)(3)(i) of 
this section, using emissions data determined in accordance with subpart 
H of part 75 of this chapter or, if the State demonstrates that 
compliance with subpart H of part 75 of this chapter is not practicable, 
determined, to the extent practicable, with the same degree of assurance 
with which emissions data are determined for sources subject to subpart 
H of part 75.
    (4) If the SIP revision contains approved provisions for an 
emissions trading program, the owners and operators of sources that 
receive credit according to the requirements of this paragraph may 
transfer the credit to other sources or persons according to the 
provisions in the emissions trading program.
    (B) The State may issue credit from the compliance supplement pool 
to sources that are required by the SIP revision to implement 
NOX emission control measures and whose owners and operators 
demonstrate a need for an extension, beyond 2009, of the deadline for 
the source for implementing such emission controls.
    (1) The State shall complete the issuance process by January 1, 
2010.
    (2) The State shall issue credit to a source only if the owners and 
operators of the source demonstrate that:
    (i) For a source used to generate electricity, implementation of the 
SIP revision's applicable control measures by 2009 would create undue 
risk for the reliability of the electricity supply. This demonstration 
must include a showing that it would not be feasible for the owners and 
operators of the source to obtain a sufficient amount of electricity, to 
prevent such undue risk, from other electricity generation facilities 
during the installation of control technology at the source necessary to 
comply with the SIP revision.
    (ii) For a source not used to generate electricity, compliance with 
the SIP revision's applicable control measures by 2009 would create 
undue risk for the source or its associated industry to a degree that is 
comparable to the risk described in paragraph (e)(4)(iii)(B)(2)(i) of 
this section.
    (iii) This demonstration must include a showing that it would not be 
possible for the source to comply with applicable control measures by 
obtaining sufficient credits under paragraph (e)(4)(iii)(A) of this 
section, or by acquiring sufficient credits from other sources or 
persons, to prevent undue risk.
    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an annual NOX

[[Page 180]]

mass emissions cap on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an annual NOX mass emissions cap on all such sources 
in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (f)(2)(ii) of this section, then those 
measures must impose an annual NOX mass emissions cap on all 
such sources in the State or the State must demonstrate why such 
emissions cap is not practicable and adopt alternative requirements that 
ensure that the State will comply with its requirements under paragraph 
(e) of this section, as applicable, in 2009 and subsequent years.
    (g)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a)(1) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Annual Non-EGU NOX Reduction Requirement 
under paragraph (e) of this section and are not adopted or implemented 
by the State, as of May 12, 2005, and are not adopted or implemented by 
the Federal government, as of the date of submission of the SIP revision 
by the State to EPA.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of NOX mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP revision.
    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with subpart H of part 75 of this 
chapter, if the source category is subject to monitoring requirements in 
accordance with subpart H of part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with subpart H 
of part 75 of this chapter, actual emissions must be quantified, to the 
maximum extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter and using source-specific or source-category-specific 
assumptions that ensure a source's or source category's actual emissions 
are not overestimated. If a State uses factors to estimate emissions, 
production or utilization, or effectiveness of controls or rules for a 
source category, such factors must be chosen to ensure that emissions 
are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of NOX mass emissions 
from the source category in the years 2009 and 2015, absent the control 
measures specified in the SIP revision and reflecting changes in these 
emissions from the historical baseline year to the years 2009 and 2015, 
based on projected changes in the production input or output, 
population, vehicle miles traveled, economic activity, or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are otherwise required by final rules already promulgated, 
as of May 12, 2005, or adopted or implemented by any federal agency, as 
of the date of submission of the SIP revision by the State to EPA, and 
must exclude any control measures specified in the SIP revision to meet 
the NOX emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and

[[Page 181]]

county of the source or source category and must be consistent with both 
national projections and relevant official planning assumptions, 
including estimates of population and vehicle miles traveled developed 
through consultation between State and local transportation and air 
quality agencies. However, if these official planning assumptions are 
inconsistent with official U.S. Census projections of population or with 
energy consumption projections contained in the U.S. Department of 
Energy's most recent Annual Energy Outlook, then the SIP revision must 
make adjustments to correct the inconsistency or must demonstrate how 
the official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2009 or 2015, as appropriate.
    (iii) A projection of NOX mass emissions in 2009 and 2015 
from the source category assuming the same projected changes as under 
paragraph (g)(2)(ii) of this section and resulting from implementation 
of each of the control measures specified in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to shift to unregulated or less stringently regulated sources in the 
source category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2009 and 2015 NOX emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
of this section for 2009 and 2015, respectively, from the lower of the 
amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2009 
and 2015, respectively, may be credited towards the State's Annual Non-
EGU NOX Reduction Requirement in paragraph (e)(3) of this 
section for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (h) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).
    (i) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then the SIP revision must 
require such sources to comply with the monitoring, recordkeeping, and 
reporting provisions of subpart H of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (i)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of

[[Page 182]]

subpart H of part 75 of this chapter, or the State must demonstrate why 
such requirements are not practicable and adopt alternative requirements 
that ensure that the required emissions reductions will be quantified, 
to the maximum extent practicable, with the same degree of assurance 
with which emissions are quantified for sources subject to subpart H of 
part 75 of this chapter.
    (j) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Annual 
EGU NOX Budget or the Annual Non-EGU NOX Reduction 
Requirement, as applicable, under paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (k)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (l)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (o)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AA through 
II of part 96 of this chapter (CAIR NOX Annual Trading 
Program), incorporates such subparts by reference into its regulations, 
or adopts regulations that differ substantively from such subparts only 
as set forth in paragraph (o)(2) of this section, then such emissions 
trading program in the State's SIP revision is automatically approved as 
meeting the requirements of paragraph (e) of this section, provided that 
the State has the legal authority to take such action and to implement 
its responsibilities under such regulations. Before January 1, 2009, a 
State's regulations shall be considered to be substantively identical to 
subparts AA through II of part 96 of this chapter, or differing 
substantively only as set forth in paragraph (o)(2) of this section, 
regardless of whether the State's regulations include the definition of 
``Biomass'', paragraph (3) of the definition of ``Cogeneration unit'', 
and the second sentence of the definition of ``Total energy input'' in 
Sec. 96.102 of this chapter promulgated on October 19, 2007, provided 
that the State timely submits to the Administrator a SIP revision that 
revises the State's regulations to include such provisions. Submission 
to the Administrator of a SIP revision that revises the State's 
regulations to include such provisions shall be considered timely if the 
submission is made by January 1, 2009.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AA through II of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (o)(1) of this section.

[[Page 183]]

    (i) The State may decline to adopt the CAIR NOX opt-in 
provisions of:
    (A) Subpart II of this part and the provisions applicable only to 
CAIR NOX opt-in units in subparts AA through HH of this part;
    (B) Section 96.188(b) of this chapter and the provisions of subpart 
II of this part applicable only to CAIR NOX opt-in units 
under Sec. 96.188(b); or
    (C) Section 96.188(c) of this chapter and the provisions of subpart 
II of this part applicable only to CAIR NOX opt-in units 
under Sec. 96.188(c).
    (ii) The State may decline to adopt the allocation provisions set 
forth in subpart EE of part 96 of this chapter and may instead adopt any 
methodology for allocating CAIR NOX allowances to individual 
sources, as follows:
    (A) The State's methodology must not allow the State to allocate 
CAIR NOX allowances for a year in excess of the amount in the 
State's Annual EGU NOX Budget for such year;
    (B) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the State will determine, and notify 
the Administrator of, each unit's allocation of CAIR NOX 
allowances by October 31, 2006 for 2009, 2010, and 2011 and by October 
31, 2008 and October 31 of each year thereafter for 4th the year after 
the year of the notification deadline;
    (C) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the State will determine, and 
notify the Administrator of, each unit's allocation of CAIR 
NOX allowances by October 31 of the year for which the CAIR 
NOX allowances are allocated; and
    (D) The State's methodology for allocating the compliance supplement 
pool must be substantively identical to Sec. 97.143 (except that the 
permitting authority makes the allocations and the Administrator records 
the allocations made by the permitting authority) or otherwise in 
accordance with paragraph (e)(4) of this section.
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (o)(1) or (2) of this section is not required to adopt an 
emissions trading program in accordance with paragraph (aa)(1) or (2) of 
this section or Sec. 96.124(o)(1) or (2).
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AA through HH of part 96 of this chapter, 
other than as set forth in paragraph (o)(2) of this section, then such 
emissions trading program is not automatically approved as set forth in 
paragraph (o)(1) or (2) of this section and will be reviewed by the 
Administrator for approvability in accordance with the other provisions 
of this section, provided that the NOX allowances issued 
under such emissions trading program shall not, and the SIP revision 
shall state that such NOX allowances shall not, qualify as 
CAIR NOX allowances or CAIR NOX Ozone Season 
allowances under any emissions trading program approved under paragraphs 
(o)(1) or (2) or (aa)(1) or (2) of this section.
    (p) Notwithstanding any other provision of this section, a State may 
adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR NOX Annual Trading 
Program under subparts AA through HH of part 97 of this chapter as 
follows:
    (1) The State may adopt, as CAIR NOX allowance allocation 
provisions replacing the provisions in subpart EE of part 97 of this 
chapter:
    (i) Allocation provisions substantively identical to subpart EE of 
part 96 of this chapter, under which the permitting authority makes the 
allocations; or
    (ii) Any methodology for allocating CAIR NOX allowances 
to individual sources under which the permitting authority makes the 
allocations, provided that:
    (A) The State's methodology must not allow the permitting authority 
to allocate CAIR NOX allowances for a year in excess of the 
amount in the State's Annual EGU NOX budget for such year.
    (B) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by April 30, 2007 for 2009, 2010, and 
2011 and by October 31, 2008 and October 31 of each year thereafter for 
the 4th

[[Page 184]]

year after the year of the notification deadline.
    (C) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31 of the year for which the 
CAIR NOX allowances are allocated.
    (2) The State may adopt, as compliance supplement pool provisions 
replacing the provisions in Sec. 97.143 of this chapter:
    (i) Provisions for allocating the State's compliance supplement pool 
that are substantively identical to Sec. 97.143 of this chapter, except 
that the permitting authority makes the allocations and the 
Administrator records the allocations made by the permitting authority;
    (ii) Provisions for allocating the State's compliance supplement 
pool that are substantively identical to Sec. 96.143 of this chapter; 
or
    (iii) Other provisions for allocating the State's compliance 
supplement pool that are in accordance with paragraph (e)(4) of this 
section.
    (3) The State may adopt CAIR opt-in unit provisions as follows:
    (i) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in 
units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied;
    (ii) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in 
units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied, 
except that the provisions exclude Sec. 96.188(b) of this chapter and 
the provisions of subpart II of part 96 of this chapter that apply only 
to units covered by Sec. 96.188(b) of this chapter; or
    (iii) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in 
units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied, 
except that the provisions exclude Sec. 96.188(c) of this chapter and 
the provisions of subpart II of part 96 of this chapter that apply only 
to units covered by Sec. 96.188(c) of this chapter.
    (q) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Ozone 
Season EGU NOX Budget, if applicable, and achieve the State's 
Ozone Season Non-EGU NOX Reduction Requirement, if 
applicable, for the appropriate periods. The amounts of the State's 
Ozone Season EGU NOX Budget and Ozone Season Non-EGU 
NOX Reduction Requirement shall be determined as follows:
    (1)(i) The Ozone Season EGU NOX Budget for the State is 
defined as the total amount of NOX emissions from all EGUs in 
that State for an ozone season, if the State meets the requirements of 
paragraph (a)(2) of this section by imposing control measures, at least 
in part, on EGUs. If the State imposes control measures under this 
section on only EGUs, the Ozone Season EGU NOX Budget for the 
State shall not exceed the amount, during the indicated periods, 
specified in paragraph (q)(2) of this section.
    (ii) The Ozone Season Non-EGU NOX Reduction Requirement, 
if applicable, is defined as the total amount of NOX emission 
reductions that the State

[[Page 185]]

demonstrates, in accordance with paragraph (s) of this section, it will 
achieve from non-EGUs during the appropriate period. If the State meets 
the requirements of paragraph (a)(2) of this section by imposing control 
measures on only non-EGUs, then the State's Ozone Season Non-EGU 
NOX Reduction Requirement shall equal or exceed, during the 
appropriate periods, the amount determined in accordance with paragraph 
(q)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a)(2) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Ozone Season Non-EGU NOX Reduction Requirement 
shall equal or exceed the difference between the amount specified in 
paragraph (q)(2) of this section for the appropriate period and the 
amount of the State's Ozone Season EGU NOX Budget specified 
in the SIP revision for the appropriate period; and
    (B) The Ozone Season EGU NOX Budget shall not exceed, 
during the indicated periods, the amount specified in paragraph (q)(2) 
of this section plus the amount of the Ozone Season Non-EGU 
NOX Reduction Requirement under paragraph (q)(1)(iii)(A) of 
this section for the appropriate period.
    (2) For a State that complies with the requirements of paragraph 
(a)(2) of this section by imposing control measures on only EGUs, the 
amount of the Ozone Season EGU NOX Budget, in tons of 
NOX per ozone season, shall be as follows, for the indicated 
State for the indicated period:

------------------------------------------------------------------------
                                                           Ozone season
                                           Ozone season   EGU NOX budget
                  State                   EGU NOX budget   for 2015 and
                                           for 2009-2014    thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          32,182          26,818
Arkansas................................          11,515           9,596
Connecticut.............................           2,559           2,559
Delaware................................           2,226           1,855
District of Columbia....................             112              94
Florida.................................          47,912          39,926
Illinois................................          30,701          28,981
Indiana.................................          45,952          39,273
Iowa....................................          14,263          11,886
Kentucky................................          36,045          30,587
Louisiana...............................          17,085          14,238
Maryland................................          12,834          10,695
Massachusetts...........................           7,551           6,293
Michigan................................          28,971          24,142
Mississippi.............................           8,714           7,262
Missouri................................          26,678          22,231
New Jersey..............................           6,654           5,545
New York................................          20,632          17,193
North Carolina..........................          28,392          23,660
Ohio....................................          45,664          39,945
Pennsylvania............................          42,171          35,143
South Carolina..........................          15,249          12,707
Tennessee...............................          22,842          19,035
Virginia................................          15,994          13,328
West Virginia...........................          26,859          26,525
Wisconsin...............................          17,987          14,989
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph 
(a)(2) of this section by imposing control measures on only non-EGUs, 
the amount of the Ozone Season Non-EGU NOX Reduction 
Requirement, in tons of NOX per ozone season, shall be 
determined, for the State for 2009 and thereafter, by subtracting the 
amount of the State's Ozone Season EGU NOX Budget for the 
appropriate year, specified in paragraph (q)(2) of this section, from 
the amount of the State's NOX baseline EGU emissions 
inventory projected for the ozone season in the appropriate year, 
specified in Table 7 of ``Regional and State SO2 and 
NOX Budgets'', March 2005 (available at: http://www.epa.gov/
cleanairinterstaterule).
    (4) Notwithstanding the State's obligation to comply with paragraph 
(q)(2) or (3) of this section, the State's SIP revision may allow 
sources required by the revision to implement NOX emission 
control measures to demonstrate compliance using NOX SIP Call 
allowances allocated under the NOX Budget Trading Program for 
any ozone season during 2003 through 2008 that have not been deducted by 
the Administrator under the NOX Budget Trading Program, if 
the SIP revision ensures that such allowances will not be available for 
such deduction under the NOX Budget Trading Program.
    (r) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (q) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;

[[Page 186]]

    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an ozone season NOX mass emissions 
cap on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an ozone season NOX mass emissions cap on all such 
sources in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (r)(2)(ii) of this section, then those 
measures must impose an ozone season NOX mass emissions cap 
on all such sources in the State or the State must demonstrate why such 
emissions cap is not practicable and adopt alternative requirements that 
ensure that the State will comply with its requirements under paragraph 
(q) of this section, as applicable, in 2009 and subsequent years.
    (s)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a)(2) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Ozone Season Non-EGU NOX Reduction 
Requirement under paragraph (q) of this section and are not adopted or 
implemented by the State, as of May 12, 2005, and are not adopted or 
implemented by the federal government, as of the date of submission of 
the SIP revision by the State to EPA.
    (2) The demonstration under paragraph (s)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of NOX mass 
emissions from the source category in a representative ozone season 
consisting, at the State's election, of the ozone season in 2002, 2003, 
2004, or 2005, or an average of 2 or more of those ozone seasons, absent 
the control measures specified in the SIP revision.
    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with subpart H of part 75 of this 
chapter, if the source category is subject to monitoring requirements in 
accordance with subpart H of part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with subpart H 
of part 75 of this chapter, actual emissions must be quantified, to the 
maximum extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter and using source-specific or source-category-specific 
assumptions that ensure a source's or source category's actual emissions 
are not overestimated. If a State uses factors to estimate emissions, 
production or utilization, or effectiveness of controls or rules for a 
source category, such factors must be chosen to ensure that emissions 
are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of NOX mass emissions 
from the source category in ozone seasons 2009 and 2015, absent the 
control measures specified in the SIP revision and reflecting changes in 
these emissions from the historical baseline ozone season to the ozone 
seasons 2009 and 2015, based on projected changes in the production 
input or output, population, vehicle miles traveled, economic activity, 
or other factors as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are adopted or implemented by the State, as of May 12, 
2005,

[[Page 187]]

or adopted or implemented by the federal government, as of the date of 
submission of the SIP revision by the State to EPA, and must exclude any 
control measures specified in the SIP revision to meet the 
NOX emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category and must be consistent with both national projections 
and relevant official planning assumptions including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are inconsistent with 
official U.S. Census projections of population or with energy 
consumption projections contained in the U.S. Department of Energy's 
most recent Annual Energy Outlook, then the SIP revision must make 
adjustments to correct the inconsistency or must demonstrate how the 
official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline ozone season and ozone season 2009 or 
ozone season 2015, as appropriate.
    (iii) A projection of NOX mass emissions in ozone season 
2009 and ozone season 2015 from the source category assuming the same 
projected changes as under paragraph (s)(2)(ii) of this section and 
resulting from implementation of each of the control measures specified 
in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to shift to unregulated or less stringently regulated sources in the 
source category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected ozone season 2009 and ozone season 2015 NOX 
emissions that will be achieved from the implementation of the new 
control measures compared to the relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (s)(2)(iii) 
of this section for ozone season 2009 and ozone season 2015, 
respectively, from the lower of the amounts in paragraph (s)(2)(i) or 
(s)(2)(ii) of this section for ozone season 2009 and ozone season 2015, 
respectively, may be credited towards the State's Ozone Season Non-EGU 
NOX Reduction Requirement in paragraph (q)(3) of this section 
for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (t) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).
    (u) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (q) of this section as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-

[[Page 188]]

EGUs that are boilers or combustion turbines with a maximum design heat 
input greater than 250 mmBtu/hr, then the SIP revision must require such 
sources to comply with the monitoring, recordkeeping, and reporting 
provisions of subpart H of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (u)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter, or the State must demonstrate why such requirements 
are not practicable and adopt alternative requirements that ensure that 
the required emissions reductions will be quantified, to the maximum 
extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter.
    (v) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Ozone 
Season EGU NOX Budget or the Ozone Season Non-EGU 
NOX Reduction Requirement, as applicable, under paragraph (q) 
of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; and
    (ii) Make the data described in paragraph (v)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (w)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (v)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (x)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (y) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).
    (z) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (aa)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AAAA 
through IIII of part 96 of this chapter (CAIR Ozone Season 
NOX Trading Program), incorporates such subparts by reference 
into its regulations, or adopts regulations that differ substantively 
from such subparts only as set forth in paragraph (aa)(2) of this 
section, then such emissions trading program in the State's SIP revision 
is automatically approved as meeting the requirements of paragraph (q) 
of this section, provided that the State has the legal authority to take 
such action and to implement its responsibilities under such 
regulations. Before January 1, 2009, a State's regulations shall be 
considered to be substantively identical to subparts AAAA through IIII 
of part 96 of the chapter, or differing substantively only as set forth 
in paragraph (o)(2) of this section, regardless of whether the State's 
regulations include the definition of ``Biomass'', paragraph (3) of the 
definition of ``Cogeneration unit'', and the second sentence of the 
definition of ``Total energy input'' in Sec. 96.302 of this chapter 
promulgated on October 19, 2007, provided that the State timely submits 
to the Administrator a SIP revision that

[[Page 189]]

revises the State's regulations to include such provisions. Submission 
to the Administrator of a SIP revision that revises the State's 
regulations to include such provisions shall be considered timely if the 
submission is made by January 1, 2009.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AAAA through IIII of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (aa)(1) of this section.
    (i) The State may expand the applicability provisions in Sec. 
96.304 to include all non-EGUs subject to the State's emissions trading 
program approved under Sec. 51.121(p).
    (ii) The State may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (A) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (B) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (C) Section 96.388(c) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(c).
    (iii) The State may decline to adopt the allocation provisions set 
forth in subpart EEEE of part 96 of this chapter and may instead adopt 
any methodology for allocating CAIR NOX Ozone Season 
allowances to individual sources, as follows:
    (A) The State may provide for issuance of an amount of CAIR Ozone 
Season NOX allowances for an ozone season, in addition to the 
amount in the State's Ozone Season EGU NOX Budget for such 
ozone season, not exceeding the amount of NOX SIP Call 
allowances allocated for the ozone season under the NOX 
Budget Trading Program to non-EGUs that the applicability provisions in 
Sec. 96.304 are expanded to include under paragraph (aa)(2)(i) of this 
section;
    (B) The State's methodology must not allow the State to allocate 
CAIR Ozone Season NOX allowances for an ozone season in 
excess of the amount in the State's Ozone Season EGU NOX 
Budget for such ozone season plus any additional amount of CAIR Ozone 
Season NOX allowances issued under paragraph (aa)(2)(iii)(A) 
of this section for such ozone season;
    (C) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the State will determine, and notify 
the Administrator of, each unit's allocation of CAIR NOX 
allowances by October 31, 2006 for the ozone seasons 2009, 2010, and 
2011 and by October 31, 2008 and October 31 of each year thereafter for 
the ozone season in the 4th year after the year of the notification 
deadline; and
    (D) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the State will determine, and 
notify the Administrator of, each unit's allocation of CAIR Ozone Season 
NOX allowances by July 31 of the calendar year of the ozone 
season for which the CAIR Ozone Season NOX allowances are 
allocated.
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (aa)(1) or (2) of this section is not required to adopt 
an emissions trading program in accordance with paragraph (o)(1) or (2) 
of this section or Sec. 51.153(o)(1) or (2).
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AAAA through IIII of part 96 of this 
chapter, other than as set forth in paragraph (aa)(2) of this section, 
then such emissions trading program is not automatically approved as set 
forth in paragraph (aa)(1) or (2) of this section and will be reviewed 
by the Administrator for approvability in accordance with the other 
provisions of this section, provided that the NOX allowances 
issued under such emissions trading program shall not, and the SIP 
revision shall state that such NOX allowances shall not, 
qualify as CAIR NOX allowances or CAIR Ozone Season 
NOX allowances under any emissions trading program approved 
under paragraphs (o)(1) or (2) or (aa)(1) or (2) of this section.

[[Page 190]]

    (bb)(1)(i) The State may revise its SIP to provide that, for each 
ozone season during which a State implements control measures on EGUs or 
non-EGUs through an emissions trading program approved under paragraph 
(aa)(1) or (2) of this section, such EGUs and non-EGUs shall not be 
subject to the requirements of the State's SIP meeting the requirements 
of Sec. 51.121, if the State meets the requirement in paragraph 
(bb)(1)(ii) of this section.
    (ii) For a State under paragraph (bb)(1)(i) of this section, if the 
State's amount of tons specified in paragraph (q)(2) of this section 
exceeds the State's amount of NOX SIP Call allowances 
allocated for the ozone season in 2009 or in any year thereafter for the 
same types and sizes of units as those covered by the amount of tons 
specified in paragraph (q)(2) of this section, then the State must 
replace the former amount for such ozone season by the latter amount for 
such ozone season in applying paragraph (q) of this section.
    (2) Rhode Island may revise its SIP to provide that, for each ozone 
season during which Rhode Island implements control measures on EGUs and 
non-EGUs through an emissions trading program adopted in regulations 
that differ substantively from subparts AAAA through IIII of part 96 of 
this chapter as set forth in this paragraph, such EGUs and non-EGUs 
shall not be subject to the requirements of the State's SIP meeting the 
requirements of Sec. 51.121.
    (i) Rhode Island must expand the applicability provisions in Sec. 
96.304 to include all non-EGUs subject to Rhode Island's emissions 
trading program approved under Sec. 51.121(p).
    (ii) Rhode Island may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (A) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (B) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (C) Section 96.388(c) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(c).
    (iii) Rhode Island may adopt the allocation provisions set forth in 
subpart EEEE of part 96 of this chapter, provided that Rhode Island must 
provide for issuance of an amount of CAIR Ozone Season NOX 
allowances for an ozone season not exceeding 936 tons for 2009 and 
thereafter;
    (iv) Rhode Island may adopt any methodology for allocating CAIR 
NOX Ozone Season allowances to individual sources, as 
follows:
    (A) Rhode Island's methodology must not allow Rhode Island to 
allocate CAIR Ozone Season NOX allowances for an ozone season 
in excess of 936 tons for 2009 and thereafter;
    (B) Rhode Island's methodology must require that, for EGUs 
commencing operation before January 1, 2001, Rhode Island will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31, 2006 for the ozone seasons 
2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the ozone season in the 4th year after the year of the 
notification deadline; and
    (C) Rhode Island's methodology must require that, for EGUs 
commencing operation on or after January 1, 2001, Rhode Island will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR Ozone Season NOX allowances by July 31 of the calendar 
year of the ozone season for which the CAIR Ozone Season NOX 
allowances are allocated.
    (3) Notwithstanding a SIP revision by a State authorized under 
paragraph (bb)(1) of this section or by Rhode Island under paragraph 
(bb)(2) of this section, if the State's or Rhode Island's SIP that, 
without such SIP revision, imposes control measures on EGUs or non-EGUs 
under Sec. 51.121 is determined by the Administrator to meet the 
requirements of Sec. 51.121, such SIP shall be deemed to continue to 
meet the requirements of Sec. 51.121.
    (cc) The terms used in this section shall have the following 
meanings:

[[Page 191]]

    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to allowances, the 
determination of the amount of allowances to be initially credited to a 
source or other entity.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber.
    Electric generating unit or EGU means:
    (1)(i) Except as provided in paragraph (2) of this definition, a 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, since the later of November 15, 
1990 or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale.
    (ii) If a stationary boiler or stationary combustion turbine that, 
under paragraph (1)(i) of this section, is not an electric generating 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more

[[Page 192]]

than 25 MWe producing electricity for sale, the unit shall become an 
electric generating unit as provided in paragraph (1)(i) of this section 
on the first date on which it both combusts fossil fuel and serves such 
generator.
    (2) A unit that meets the requirements set forth in paragraphs 
(2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall 
not be an electric generating unit:
    (i)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition:
    (1) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (2) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (B) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (2)(i)(A) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become an electric generating unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (2)(i)(A)(2) of this section.
    (ii)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation before January 1, 
1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (B) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation on or after 
January 1, 1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (C) If a unit qualifies as a solid waste incineration unit and meets 
the requirements of paragraph (2)(ii)(A) or (B) of this section for at 
least 3 consecutive calendar years, but subsequently no longer meets all 
such requirements, the unit shall become an electric generating unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Generator means a device that produces electricity.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as of such installation as specified by the manufacturer of 
the generator or, starting from the completion of any subsequent

[[Page 193]]

physical change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Non-EGU means a source of NOX emissions that is not an 
EGU.
    NOX Budget Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts A through 
I of this part and Sec. 51.121, as a means of mitigating interstate 
transport of ozone and nitrogen oxides.
    NOX SIP Call allowance means a limited authorization 
issued by the Administrator under the NOX Budget Trading 
Program to emit up to one ton of nitrogen oxides during the ozone season 
of the specified year or any year thereafter, provided that the 
provision in Sec. 51.121(b)(2)(ii)(E) shall not be used in applying 
this definition.
    Ozone season means the period, which begins May 1 and ends September 
30 of any year.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself. Each form of energy supplied 
shall be measured by the lower heating value of that form of energy 
calculated as follows:


LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or a stationary, 
fossil-fuel-fired combustion turbine.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, excluding 
any heat contained in condensate return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.
    (dd) New Hampshire may revise its SIP to implements control measures 
on EGUs and non-EGUs through an emissions trading program adopted in 
regulations that differ substantively from subparts AAAA through IIII of 
part 96 of this chapter as set forth in this paragraph.

[[Page 194]]

    (1) New Hampshire must expand the applicability provisions in Sec. 
96.304 of this chapter to include all non-EGUs subject to New 
Hampshire's emissions trading program at New Hampshire Code of 
Administrative Rules, chapter Env-A 3200 (2004).
    (2) New Hampshire may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (i) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (ii) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (iii) Section 96.388(c) of this chapter and the provisions of 
subpart IIII of this part applicable only to CAIR NOX Ozone 
Season opt-in units under Sec. 96.388(c).
    (3) New Hampshire may adopt the allocation provisions set forth in 
subpart EEEE of part 96 of this chapter, provided that New Hampshire 
must provide for issuance of an amount of CAIR Ozone Season 
NOX allowances for an ozone season not exceeding 3,000 tons 
for 2009 and thereafter;
    (4) New Hampshire may adopt any methodology for allocating CAIR 
NOX Ozone Season allowances to individual sources, as 
follows:
    (i) New Hampshire's methodology must not allow New Hampshire to 
allocate CAIR Ozone Season NOX allowances for an ozone season 
in excess of 3,000 tons for 2009 and thereafter;
    (ii) New Hampshire's methodology must require that, for EGUs 
commencing operation before January 1, 2001, New Hampshire will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31, 2006 for the ozone seasons 
2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the ozone season in the 4th year after the year of the 
notification deadline; and
    (iii) New Hampshire's methodology must require that, for EGUs 
commencing operation on or after January 1, 2001, New Hampshire will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR Ozone Season NOX allowances by July 31 of the calendar 
year of the ozone season for which the CAIR Ozone Season NOX 
allowances are allocated.
    (ee) Notwithstanding any other provision of this section, a State 
may adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR NOX Ozone Season 
Trading Program under subparts AAAA through HHHH of part 97 of this 
chapter as follows:
    (1) The State may adopt, as applicability provisions replacing the 
provisions in Sec. 97.304 of this chapter, provisions for applicability 
that are substantively identical to the provisions in Sec. 96.304 of 
this chapter expanded to include all non-EGUs subject to the State's 
emissions trading program approved under Sec. 51.121(p). Before January 
1, 2009, a State's applicability provisions shall be considered to be 
substantively identical to Sec. 96.304 of this chapter (with the 
expansion allowed under this paragraph) regardless of whether the 
State's regulations include the definition of ``Biomass'', paragraph (3) 
of the definition of ``Cogeneration unit'', and the second sentence of 
the definition of ``Total energy input'' in Sec. 97.102 of this chapter 
promulgated on October 19, 2007, provided that the State timely submits 
to the Administrator a SIP revision that revises the State's regulations 
to include such provisions. Submission to the Administrator of a SIP 
revision that revises the State's regulations to include such provisions 
shall be considered timely if the submission is made by January 1, 2009.
    (2) The State may adopt, as CAIR NOX Ozone Season 
allowance allocation provisions replacing the provisions in subpart EEEE 
of part 97 of this chapter:
    (i) Allocation provisions substantively identical to subpart EEEE of 
part 96 of this chapter, under which the permitting authority makes the 
allocations; or
    (ii) Any methodology for allocating CAIR NOX Ozone Season 
allowances to individual sources under which the permitting authority 
makes the allocations, provided that:
    (A) The State may provide for issuance of an amount of CAIR Ozone

[[Page 195]]

Season NOX allowances for an ozone season, in addition to the 
amount in the State's Ozone Season EGU NOX Budget for such 
ozone season, not exceeding the portion of the State's trading program 
budget, under the State's emissions trading program approved under Sec. 
51.121(p), attributed to the non-EGUs that the applicability provisions 
in Sec. 96.304 of this chapter are expanded to include under paragraph 
(ee)(1) of this section.
    (B) The State's methodology must not allow the State to allocate 
CAIR Ozone Season NOX allowances for an ozone season in 
excess of the amount in the State's Ozone Season EGU NOX 
Budget for such ozone season plus any additional amount of CAIR Ozone 
Season NOX allowances issued under paragraph (ee)(2)(ii)(A) 
of this section for such ozone season.
    (C) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX Ozone Season allowances by April 30, 2007 for 2009, 
2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the 4th year after the year of the notification deadline.
    (D) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX Ozone Season allowances by July 31 of the year for 
which the CAIR NOX Ozone Season allowances are allocated.
    (3) The State may adopt CAIR opt-in unit provisions as follows:
    (i) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX Ozone Season allowances for CAIR opt-in units, 
that are substantively identical to subpart IIII of part 96 of this 
chapter and the provisions of subparts AAAA through HHHH that are 
applicable to CAIR opt-in units or units for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied;
    (ii) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX Ozone Season allowances for CAIR opt-in units, 
that are substantively identical to subpart IIII of part 96 of this 
chapter and the provisions of subparts AAAA through HHHH that are 
applicable to CAIR opt-in units or units for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied, except that the provisions exclude Sec. 
96.388(b) of this chapter and the provisions of subpart IIII of part 96 
of this chapter that apply only to units covered by Sec. 96.388(b) of 
this chapter; or
    (iii) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart IIII of part 96 of this chapter and 
the provisions of subparts AAAA through HHHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied, except that the provisions exclude Sec. 96.388(c) of this 
chapter and the provisions of subpart IIII of part 96 of this chapter 
that apply only to units covered by Sec. 96.388(c) of this chapter.

[70 FR 25319, May 12, 2005, as amended at 71 FR 25301, 25370, Apr. 28, 
2006; 71 FR 74793, Dec. 13, 2006; 72 FR 59203, Oct. 19, 2007]



Sec. 51.124  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of sulfur dioxide

pursuant to the Clean Air Interstate Rule.

    (a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c) of 
this section must submit a SIP revision to comply with the requirements 
of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), 
through the adoption

[[Page 196]]

of adequate provisions prohibiting sources and other activities from 
emitting SO2 in amounts that will contribute significantly to 
nonattainment in, or interfere with maintenance by, one or more other 
States with respect to the fine particles (PM2.5) NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) of this section will contain 
adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision contains control measures that assure compliance with 
the applicable requirements of this section.
    (c) The following States are subject to the requirements of this 
section: Alabama, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 
South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin, 
and the District of Columbia.
    (d)(1) The SIP revision under paragraph (a) of this section must be 
submitted to EPA by no later than September 11, 2006.
    (2) The requirements of appendix V to this part shall apply to the 
SIP revision under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision under 
paragraph (a) of this section to the appropriate Regional Office, with a 
letter giving notice of such action.
    (e) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Annual 
EGU SO2 Budget, if applicable, and achieve the State's Annual 
Non-EGU SO2 Reduction Requirement, if applicable, for the 
appropriate periods. The amounts of the State's Annual EGU 
SO2 Budget and Annual Non-EGU SO2 Reduction 
Requirement shall be determined as follows:
    (1)(i) The Annual EGU SO2 Budget for the State is defined 
as the total amount of SO2 emissions from all EGUs in that 
State for a year, if the State meets the requirements of paragraph (a) 
of this section by imposing control measures, at least in part, on EGUs. 
If the State imposes control measures under this section on only EGUs, 
the Annual EGU SO2 Budget for the State shall not exceed the 
amount, during the indicated periods, specified in paragraph (e)(2) of 
this section.
    (ii) The Annual Non-EGU SO2 Reduction Requirement, if 
applicable, is defined as the total amount of SO2 emission 
reductions that the State demonstrates, in accordance with paragraph (g) 
of this section, it will achieve from non-EGUs during the appropriate 
period. If the State meets the requirements of paragraph (a) of this 
section by imposing control measures on only non-EGUs, then the State's 
Annual Non-EGU SO2 Reduction Requirement shall equal or 
exceed, during the appropriate periods, the amount determined in 
accordance with paragraph (e)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Annual Non-EGU SO2 Reduction Requirement shall 
equal or exceed the difference between the amount specified in paragraph 
(e)(2) of this section for the appropriate period and the amount of the 
State's Annual EGU SO2 Budget specified in the SIP revision 
for the appropriate period; and
    (B) The Annual EGU SO2 Budget shall not exceed, during 
the indicated periods, the amount specified in paragraph (e)(2) of this 
section plus the amount of the Annual Non-EGU SO2 Reduction 
Requirement under paragraph (e)(1)(iii)(A) of this section for the 
appropriate period.
    (2) For a State that complies with the requirements of paragraph (a) 
of this section by imposing control measures on only EGUs, the amount of 
the Annual EGU SO2 Budget, in tons of SO2 per 
year, shall be as follows, for the indicated State for the indicated 
period:

------------------------------------------------------------------------
                                 Annual EGU SO2        Annual EGU SO2
            State             budget for 2010-2014   budget for 2015 and
                                     (tons)           thereafter (tons)
------------------------------------------------------------------------
Alabama.....................               157,582               110,307

[[Page 197]]

 
Delaware....................                22,411                15,687
District of Columbia........                   708                   495
Florida.....................               253,450               177,415
Georgia.....................               213,057               149,140
Illinois....................               192,671               134,869
Indiana.....................               254,599               178,219
Iowa........................                64,095                44,866
Kentucky....................               188,773               132,141
Louisiana...................                59,948                41,963
Maryland....................                70,697                49,488
Michigan....................               178,605               125,024
Minnesota...................                49,987                34,991
Mississippi.................                33,763                23,634
Missouri....................               137,214                96,050
New Jersey..................                32,392                22,674
New York....................               135,139                94,597
North Carolina..............               137,342                96,139
Ohio........................               333,520               233,464
Pennsylvania................               275,990               193,193
South Carolina..............                57,271                40,089
Tennessee...................               137,216                96,051
Texas.......................               320,946               224,662
Virginia....................                63,478                44,435
West Virginia...............               215,881               151,117
Wisconsin...................                87,264                61,085
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph (a) 
of this section by imposing control measures on only non-EGUs, the 
amount of the Annual Non-EGU SO2 Reduction Requirement, in 
tons of SO2 per year, shall be determined, for the State for 
2010 and thereafter, by subtracting the amount of the State's Annual EGU 
SO2 Budget for the appropriate year, specified in paragraph 
(e)(2) of this section, from an amount equal to 2 times the State's 
Annual EGU SO2 Budget for 2010 through 2014, specified in 
paragraph (e)(2) of this section.
    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an annual SO2 mass emissions cap 
on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an annual SO2 mass emissions cap on all such sources 
in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (f)(2)(ii) of this section, then those 
measures must impose an annual SO2 mass emissions cap on all 
such sources in the State, or the State must demonstrate why such 
emissions cap is not practicable, and adopt alternative requirements 
that ensure that the State will comply with its requirements under 
paragraph (e) of this section, as applicable, in 2010 and subsequent 
years.
    (g)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Annual Non-EGU SO2 Reduction Requirement 
under paragraph (e) of this section and are not adopted or implemented 
by the

[[Page 198]]

State, as of May 12, 2005, and are not adopted or implemented by the 
federal government, as of the date of submission of the SIP revision by 
the State to EPA.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of SO2 mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP revision.
    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with part 75 of this chapter, if 
the source category is subject to part 75 monitoring requirements in 
accordance with part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with part 75 of 
this chapter, actual emissions must be quantified, to the maximum extent 
practicable, with the same degree of assurance with which emissions are 
quantified for sources subject to part 75 of this chapter and using 
source-specific or source-category-specific assumptions that ensure a 
source's or source category's actual emissions are not overestimated. If 
a State uses factors to estimate emissions, production or utilization, 
or effectiveness of controls or rules for a source category, such 
factors must be chosen to ensure that emissions are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of SO2 mass emissions 
from the source category in the years 2010 and 2015, absent the control 
measures specified in the SIP revision and reflecting changes in these 
emissions from the historical baseline year to the years 2010 and 2015, 
based on projected changes in the production input or output, 
population, vehicle miles traveled, economic activity, or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are adopted or implemented by the State, as of May 12, 
2005, or adopted or implemented by the federal government, as of the 
date of submission of the SIP revision by the State to EPA, and must 
exclude any control measures specified in the SIP revision to meet the 
SO2 emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category and must be consistent with both national projections 
and relevant official planning assumptions, including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are inconsistent with 
official U.S. Census projections of population or with energy 
consumption projections contained in the U.S. Department of Energy's 
most recent Annual Energy Outlook, then the SIP revision must make 
adjustments to correct the inconsistency or must demonstrate how the 
official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2010 or 2015, as appropriate.
    (iii) A projection of SO2 mass emissions in 2010 and 2015 
from the source category assuming the same projected changes as under 
paragraph (g)(2)(ii) of this section and resulting from implementation 
of each of the control measures specified in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to

[[Page 199]]

shift to unregulated or less stringently regulated sources in the source 
category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2010 and 2015 SO2 emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
of this section for 2010 and 2015, respectively, from the lower of the 
amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 
and 2015, respectively, may be credited towards the State's Annual Non-
EGU SO2 Reduction Requirement in paragraph (e)(3) of this 
section for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (h) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).
    (i) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section, as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of SO2 emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of part 75 of this 
chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then the SIP revision must 
require such sources to comply with the monitoring, recordkeeping, and 
reporting provisions of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (i)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of part 75 of this 
chapter, or the State must demonstrate why such requirements are not 
practicable and adopt alternative requirements that ensure that the 
required emissions reductions will be quantified, to the maximum extent 
practicable, with the same degree of assurance with which emissions are 
quantified for sources subject to part 75 of this chapter.
    (j) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Annual 
EGU SO2 Budget or the Annual Non-EGU SO2 Reduction 
Requirement, as applicable, under paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the

[[Page 200]]

State on the nature and amounts of emissions from such stationary 
sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (k)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (l)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (o)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AAA through 
III of part 96 of this chapter (CAIR SO2 Trading Program), 
incorporates such subparts by reference into its regulations, or adopts 
regulations that differ substantively from such subparts only as set 
forth in paragraph (o)(2) of this section, then such emissions trading 
program in the State's SIP revision is automatically approved as meeting 
the requirements of paragraph (e) of this section, provided that the 
State has the legal authority to take such action and to implement its 
responsibilities under such regulations. Before January 1, 2009, a 
State's regulations shall be considered to be substantively identical to 
subparts AAA through III of part 96 of the chapter, or differing 
substantively only as set forth in paragraph (o)(2) of this section, 
regardless of whether the State's regulations include the definition of 
``Biomass'', paragraph (3) of the definition of ``Cogeneration unit'', 
and the second sentence of the definition of ``Total energy input'' in 
Sec. 96.202 of this chapter promulgated on October 19, 2007, provided 
that the State timely submits to the Administrator a SIP revision that 
revises the State's regulations to include such provisions. Submission 
to the Administrator of a SIP revision that revises the State's 
regulations to include such provisions shall be considered timely if the 
submission is made by January 1, 2009.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AAA through III of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (o)(1) of this section.
    (i) The State may decline to adopt the CAIR SO2 opt-in 
provisions of subpart III of this part and the provisions applicable 
only to CAIR SO2 opt-in units in subparts AAA through HHH of 
this part.
    (ii) The State may decline to adopt the CAIR SO2 opt-in 
provisions of Sec. 96.288(b) of this chapter and the provisions of 
subpart III of this part applicable only to CAIR SO2 opt-in 
units under Sec. 96.288(b).
    (iii) The State may decline to adopt the CAIR SO2 opt-in 
provisions of Sec. 96.288(c) of this chapter and the provisions of 
subpart II of this part applicable only to CAIR SO2 opt-in 
units under Sec. 96.288(c).
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (o)(1) or (2) of this section is not required to adopt an 
emissions trading program in accordance with Sec. 96.123 (o)(1) or (2) 
or (aa)(1) or (2) of this chapter.
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AAA through III of part 96 of this chapter, 
other than as set forth in paragraph (o)(2) of this section, then such 
emissions trading program is not automatically approved as set forth in 
paragraph (o)(1) or (2) of this section and will be reviewed by the 
Administrator for approvability in accordance with the other provisions 
of this section, provided that the SO2 allowances issued 
under such emissions trading program shall not, and the SIP

[[Page 201]]

revision shall state that such SO2 allowances shall not, 
qualify as CAIR SO2 allowances under any emissions trading 
program approved under paragraph (o)(1) or (2) of this section.
    (p) If a State's SIP revision does not contain an emissions trading 
program approved under paragraph (o)(1) or (2) of this section but 
contains control measures on EGUs as part or all of a State's obligation 
in meeting its requirement under paragraph (a) of this section:
    (1) The SIP revision shall provide, for each year that the State has 
such obligation, for the permanent retirement of an amount of Acid Rain 
allowances allocated to sources in the State for that year and not 
deducted by the Administrator under the Acid Rain Program and any 
emissions trading program approved under paragraph (o)(1) or (2) of this 
section, equal to the difference between--
    (A) The total amount of Acid Rain allowances allocated under the 
Acid Rain Program to the sources in the State for that year; and
    (B) If the State's SIP revision contains only control measures on 
EGUs, the State's Annual EGU SO2 Budget for the appropriate 
period as specified in paragraph (e)(2) of this section or, if the 
State's SIP revision contains control measures on EGUs and non-EGUs, the 
State's Annual EGU SO2 Budget for the appropriate period as 
specified in the SIP revision.
    (2) The SIP revision providing for permanent retirement of Acid Rain 
allowances under paragraph (p)(1) of this section must ensure that such 
allowances are not available for deduction by the Administrator under 
the Acid Rain Program and any emissions trading program approved under 
paragraph (o)(1) or (2) of this section.
    (q) The terms used in this section shall have the following 
meanings:
    Acid Rain allowance means a limited authorization issued by the 
Administrator under the Acid Rain Program to emit up to one ton of 
sulfur dioxide during the specified year or any year thereafter, except 
as otherwise provided by the Administrator.
    Acid Rain Program means a multi-State sulfur dioxide and nitrogen 
oxides air pollution control and emissions reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to allowances, the 
determination of the amount of allowances to be initially credited to a 
source or other entity.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted to 
energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
nonmerchantable material, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or

[[Page 202]]

cooling purposes through the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after the 
calendar year in which the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input;
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy input 
from all fuel except biomass if the unit is a boiler.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated duct burner, heat recovery steam 
generator, and steam turbine.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber.
    Electric generating unit or EGU means:
    (1)(i) Except as provided in paragraph (2) of this definition, a 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, since the later of November 15, 
1990 or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale.
    (ii) If a stationary boiler or stationary combustion turbine that, 
under paragraph (1)(i) of this section, is not an electric generating 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become an electric generating unit as provided in 
paragraph (1)(i) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (2) A unit that meets the requirements set forth in paragraphs 
(2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall 
not be an electric generating unit:
    (i)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition:
    (1) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (2) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (B) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (2)(i)(A) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become an electric generating unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (2)(i)(A)(2) of this section.
    (ii)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation before January 1, 
1985:
    (1) Qualifying as a solid waste incineration unit; and

[[Page 203]]

    (2) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (B) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation on or after 
January 1, 1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (C) If a unit qualifies as a solid waste incineration unit and meets 
the requirements of paragraph (2)(ii)(A) or (B) of this section for at 
least 3 consecutive calendar years, but subsequently no longer meets all 
such requirements, the unit shall become an electric generating unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Generator means a device that produces electricity.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a unit is capable of combusting on a steady state basis 
as of the initial installation of the unit as specified by the 
manufacturer of the unit.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other deratings 
as of such installation as specified by the manufacturer of the 
generator or, starting from the completion of any subsequent physical 
change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as of such completion as specified by the person conducting the 
physical change.
    Non-EGU means a source of SO2 emissions that is not an 
EGU.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit. Each form of energy supplied shall be measured by the 
lower heating value of

[[Page 204]]

that form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.

    Unit means a stationary, fossil-fuel-fired boiler or a stationary, 
fossil-fuel fired combustion turbine.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, excluding 
any heat contained in condensate return or makeup water;
    (2) Used in a heating application (e.g., space heating or domestic 
hot water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.
    (r) Notwithstanding any other provision of this section, a State may 
adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR SO2 Trading Program 
under subparts AAA through HHH of part 97 of this chapter as follows. 
The State may adopt the following CAIR opt-in unit provisions:
    (1) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR SO2 allowances for CAIR opt-in units, that are 
substantively identical to subpart III of part 96 of this chapter and 
the provisions of subparts AAA through HHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied;
    (2) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR SO2 allowances for CAIR opt-in units, that are 
substantively identical to subpart III of part 96 of this chapter and 
the provisions of subparts AAA through HHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied, except that the provisions exclude Sec. 96.288(b) of this 
chapter and the provisions of subpart III of part 96 of this chapter 
that apply only to units covered by Sec. 96.288(b) of this chapter; or
    (3) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR SO2 allowances for CAIR opt-in units, that are 
substantively identical to subpart III of part 96 of this chapter and 
the provisions of subparts AAA through HHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied, except that the provisions exclude Sec. 96.288(c) of this 
chapter and the provisions of subpart III of part 96 of this chapter 
that apply only to units covered by Sec. 96.288(c) of this chapter.

[70 FR 25328, May 12, 2005, as amended at 71 FR 25302, 25372, Apr. 28, 
2006; 71 FR 74793, Dec. 13, 2006; 72 FR 59204, Oct. 19, 2007]



Sec. 51.125  Emissions reporting requirements for SIP revisions 
relating to budgets for SO2 and NOX emissions.

    (a) For its transport SIP revision under Sec. 51.123 and/or 51.124, 
each State must submit to EPA SO2 and/or NOX 
emissions data as described in this section.
    (1) Alabama, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, New Jersey, New York, North Carolina,

[[Page 205]]

Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West 
Virginia, Wisconsin, and the District of Columbia must report annual (12 
months) emissions of SO2 and NOX.
    (2) Alabama, Arkansas, Connecticut, Delaware, Florida, Illinois, 
Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, 
Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, 
Wisconsin and the District of Columbia must report ozone season (May 1 
through September 30) emissions of NOX.
    (b) Each revision must provide for periodic reporting by the State 
of SO2 and/or NOX emissions data as specified in 
paragraph (a) of this section to demonstrate whether the State's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) Every-year reporting cycle. As applicable, each revision must 
provide for reporting of SO2 and NOX emissions 
data every year as follows:
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every year from all SO2 
and NOX sources within the State for which the State 
specified control measures in its SIP submission under Sec. Sec. 51.123 
and/or 51.124.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and summer daily emissions data every year 
from all NOX sources within the State for which the State 
specified control measures in its SIP submission under Sec. 51.123.
    (iii) If sources report SO2 and NOX emissions 
data to EPA in a given year pursuant to a trading program approved under 
Sec. 51.123(o) or Sec. 51.124(o) of this part or pursuant to the 
monitoring and reporting requirements of 40 CFR part 75, then the State 
need not provide annual reporting of these pollutants to EPA for such 
sources.
    (2) Three-year reporting cycle. As applicable, each plan must 
provide for triennial (i.e., every third year) reporting of 
SO2 and NOX emissions data from all sources within 
the State.
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every third year from all 
SO2 and NOX sources within the State.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and ozone daily emissions data every third 
year from all NOX sources within the State.
    (3) The data availability requirements in Sec. 51.116 must be 
followed for all data submitted to meet the requirements of paragraphs 
(b)(1) and (2) of this section.
    (c) The data reported in paragraph (b) of this section must meet the 
requirements of subpart A of this part.
    (d) Approval of annual and ozone season calculation by EPA. Each 
State must submit for EPA approval an example of the calculation 
procedure used to calculate annual and ozone season emissions along with 
sufficient information for EPA to verify the calculated value of annual 
and ozone season emissions.
    (e) Reporting schedules. (1) Reports are to begin with data for 
emissions occurring in the year 2008, which is the first year of the 3-
year cycle.
    (2) After 2008, 3-year cycle reports are to be submitted every third 
year and every-year cycle reports are to be submitted each year that a 
triennial report is not required.
    (3) States must submit data for a required year no later than 17 
months after the end of the calendar year for which the data are 
collected.
    (f) Data reporting procedures are given in subpart A of this part. 
When submitting a formal NOX budget emissions report and 
associated data, States shall notify the appropriate EPA Regional 
Office.
    (g) Definitions. (1) As used in this section, ``ozone season'' is 
defined as follows:
    Ozone season.--The five month period from May 1 through September 
30.
    (2) Other words and terms shall have the meanings set forth in 
appendix A of subpart A of this part.

[70 FR 25333, May 12, 2005, as amended at 71 FR 25302, Apr. 28, 2006; 72 
FR 55659, Oct. 1, 2007]

[[Page 206]]



        Subpart H_Prevention of Air Pollution Emergency Episodes

    Source: 51 FR 40668, Nov. 7, 1986, unless otherwise noted.



Sec. 51.150  Classification of regions for episode plans.

    (a) This section continues the classification system for episode 
plans. Each region is classified separately with respect to each of the 
following pollutants: Sulfur oxides, particulate matter, carbon 
monoxide, nitrogen dioxide, and ozone.
    (b) Priority I Regions means any area with greater ambient 
concentrations than the following:
    (1) Sulfur dioxide--100 [micro]g/m\3\ (0.04 ppm) annual arithmetic 
mean; 455 [micro]g/m\3\ (0.17 ppm) 24-hour maximum.
    (2) Particulate matter--95 [micro]g/m\3\ annual geometric mean; 325 
[micro]g/m\3\ 24-hour maximum.
    (3) Carbon monoxide--55 mg/m\3\ (48 ppm) 1-hour maximum; 14 mg/m\3\ 
(12 ppm) 8-hour maximum.
    (4) Nitrogen dioxide--100 [micro]g/m\3\ (0.06 ppm) annual arithmetic 
mean.
    (5) Ozone--195 [micro]g/m\3\ (0.10 ppm) 1-hour maximum.
    (c) Priority IA Region means any area which is Priority I primarily 
because of emissions from a single point source.
    (d) Priority II Region means any area which is not a Priority I 
region and has ambient concentrations between the following:
    (1) Sulfur Dioxides--60-100 [micro]g/m\3\ (0.02-0.04 ppm) annual 
arithmetic mean; 260-445 [micro]g/m\3\ (0.10-0.17 ppm) 24-hour maximum; 
any concentration above 1,300 [micro]g/m\3\ (0.50 ppm) three-hour 
average.
    (2) Particulate matter--60-95 [micro]g/m\3\ annual geometric mean; 
150-325 [micro]g/m\3\ 24-hour maximum.
    (e) In the absence of adequate monitoring data, appropriate models 
must be used to classify an area under paragraph (b) of this section, 
consistent with the requirements contained in Sec. 51.112(a).
    (f) Areas which do not meet the above criteria are classified 
Priority III.

[51 FR 40668, Nov. 7, 1986, as amended at 58 FR 38822, July 20, 1993]



Sec. 51.151  Significant harm levels.

    Each plan for a Priority I region must include a contingency plan 
which must, as a mimimum, provide for taking action necessary to prevent 
ambient pollutant concentrations at any location in such region from 
reaching the following levels:

Sulfur dioxide--2.620 [micro]g/m\3\ (1.0 ppm) 24-hour average.
PM10--600 micrograms/cubic meter; 24-hour average.
Carbon monoxide--57.5 mg/m\3\ (50 ppm) 8-hour average; 86.3 mg/m\3\ (75 
ppm) 4-hour average; 144 mg/m\3\ (125 ppm) 1-hour average.
Ozone--1,200 ug/m\3\ (0.6 ppm) 2-hour average.
Nitrogen dioxide--3.750 ug/m\3\ (2.0 ppm) 1-hour average; 938 ug/m\3\ 
(0.5 ppm) 24-hour average.

[51 FR 40668, Nov. 7, 1986, as amended at 52 FR 24713, July 1, 1987]



Sec. 51.152  Contingency plans.

    (a) Each contingency plan must--
    (1) Specify two or more stages of episode criteria such as those set 
forth in appendix L to this part, or their equivalent;
    (2) Provide for public announcement whenever any episode stage has 
been determined to exist; and
    (3) Specify adequate emission control actions to be taken at each 
episode stage. (Examples of emission control actions are set forth in 
appendix L.)
    (b) Each contingency plan for a Priority I region must provide for 
the following:
    (1) Prompt acquisition of forecasts of atmospheric stagnation 
conditions and of updates of such forecasts as frequently as they are 
issued by the National Weather Service.
    (2) Inspection of sources to ascertain compliance with applicable 
emission control action requirements.
    (3) Communications procedures for transmitting status reports and 
orders as to emission control actions to be taken during an episode 
stage, including procedures for contact with public officials, major 
emission sources, public health, safety, and emergency agencies and news 
media.
    (c) Each plan for a Priority IA and II region must include a 
contingency plan that meets, as a minimum, the requirements of 
paragraphs (b)(1) and (b)(2) of this section. Areas classified Priority

[[Page 207]]

III do not need to develop episode plans.
    (d) Notwithstanding the requirements of paragraphs (b) and (c) of 
this section, the Administrator may, at his discretion--
    (1) Exempt from the requirements of this section those portions of 
Priority I, IA, or II regions which have been designated as attainment 
or unclassifiable for national primary and secondary standards under 
section 107 of the Act; or
    (2) Limit the requirements pertaining to emission control actions in 
Priority I regions to--
    (i) Urbanized areas as identified in the most recent United States 
Census, and
    (ii) Major emitting facilities, as defined by section 169(1) of the 
Act, outside the urbanized areas.



Sec. 51.153  Reevaluation of episode plans.

    (a) States should periodically reevaluate priority classifications 
of all Regions or portion of Regions within their borders. The 
reevaluation must consider the three most recent years of air quality 
data. If the evaluation indicates a change to a higher priority 
classification, appropriate changes in the episode plan must be made as 
expeditiously as practicable.
    (b) [Reserved]



            Subpart I_Review of New Sources and Modifications

    Source: 51 FR 40669, Nov. 7, 1986, unless otherwise noted.



Sec. 51.160  Legally enforceable procedures.

    (a) Each plan must set forth legally enforceable procedures that 
enable the State or local agency to determine whether the construction 
or modification of a facility, building, structure or installation, or 
combination of these will result in--
    (1) A violation of applicable portions of the control strategy; or
    (2) Interference with attainment or maintenance of a national 
standard in the State in which the proposed source (or modification) is 
located or in a neighboring State.
    (b) Such procedures must include means by which the State or local 
agency responsible for final decisionmaking on an application for 
approval to construct or modify will prevent such construction or 
modification if--
    (1) It will result in a violation of applicable portions of the 
control strategy; or
    (2) It will interfere with the attainment or maintenance of a 
national standard.
    (c) The procedures must provide for the submission, by the owner or 
operator of the building, facility, structure, or installation to be 
constructed or modified, of such information on--
    (1) The nature and amounts of emissions to be emitted by it or 
emitted by associated mobile sources;
    (2) The location, design, construction, and operation of such 
facility, building, structure, or installation as may be necessary to 
permit the State or local agency to make the determination referred to 
in paragraph (a) of this section.
    (d) The procedures must provide that approval of any construction or 
modification must not affect the responsibility to the owner or operator 
to comply with applicable portions of the control strategy.
    (e) The procedures must identify types and sizes of facilities, 
buildings, structures, or installations which will be subject to review 
under this section. The plan must discuss the basis for determining 
which facilities will be subject to review.
    (f) The procedures must discuss the air quality data and the 
dispersion or other air quality modeling used to meet the requirements 
of this subpart.
    (1) All applications of air quality modeling involved in this 
subpart shall be based on the applicable models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a modification or 
substitution of a model may be made on a case-by-case basis or, where 
appropriate, on a generic basis for a specific State program.

[[Page 208]]

Written approval of the Administrator must be obtained for any 
modification or substitution. In addition, use of a modified or 
substituted model must be subject to notice and opportunity for public 
comment under procedures set forth in Sec. 51.102.

[51 FR 40669, Nov. 7, 1986, as amended at 58 FR 38822, July 20, 1993; 60 
FR 40468, Aug. 9, 1995; 61 FR 41840, Aug. 12, 1996]



Sec. 51.161  Public availability of information.

    (a) The legally enforceable procedures in Sec. 51.160 must also 
require the State or local agency to provide opportunity for public 
comment on information submitted by owners and operators. The public 
information must include the agency's analysis of the effect of 
construction or modification on ambient air quality, including the 
agency's proposed approval or disapproval.
    (b) For purposes of paragraph (a) of this section, opportunity for 
public comment shall include, as a minimum--
    (1) Availability for public inspection in at least one location in 
the area affected of the information submitted by the owner or operator 
and of the State or local agency's analysis of the effect on air 
quality;
    (2) A 30-day period for submittal of public comment; and
    (3) A notice by prominent advertisement in the area affected of the 
location of the source information and analysis specified in paragraph 
(b)(1) of this section.
    (c) Where the 30-day comment period required in paragraph (b) of 
this section would conflict with existing requirements for acting on 
requests for permission to construct or modify, the State may submit for 
approval a comment period which is consistent with such existing 
requirements.
    (d) A copy of the notice required by paragraph (b) of this section 
must also be sent to the Administrator through the appropriate Regional 
Office, and to all other State and local air pollution control agencies 
having jurisdiction in the region in which such new or modified 
installation will be located. The notice also must be sent to any other 
agency in the region having responsibility for implementing the 
procedures required under this subpart. For lead, a copy of the notice 
is required for all point sources. The definition of point for lead is 
given in Sec. 51.100(k)(2).



Sec. 51.162  Identification of responsible agency.

    Each plan must identify the State or local agency which will be 
responsible for meeting the requirements of this subpart in each area of 
the State. Where such responsibility rests with an agency other than an 
air pollution control agency, such agency will consult with the 
appropriate State or local air pollution control agency in carrying out 
the provisions of this subpart.



Sec. 51.163  Administrative procedures.

    The plan must include the administrative procedures, which will be 
followed in making the determination specified in paragraph (a) of Sec. 
51.160.



Sec. 51.164  Stack height procedures.

    Such procedures must provide that the degree of emission limitation 
required of any source for control of any air pollutant must not be 
affected by so much of any source's stack height that exceeds good 
engineering practice or by any other dispersion technique, except as 
provided in Sec. 51.118(b). Such procedures must provide that before a 
State issues a permit to a source based on a good engineering practice 
stack height that exceeds the height allowed by Sec. 51.100(ii) (1) or 
(2), the State must notify the public of the availability of the 
demonstration study and must provide opportunity for public hearing on 
it. This section does not require such procedures to restrict in any 
manner the actual stack height of any source.



Sec. 51.165  Permit requirements.

    (a) State Implementation Plan and Tribal Implementation Plan 
provisions satisfying sections 172(c)(5) and 173 of the Act shall meet 
the following conditions:
    (1) All such plans shall use the specific definitions. Deviations 
from the following wording will be approved only if the State 
specifically demonstrates that the submitted definition

[[Page 209]]

is more stringent, or at least as stringent, in all respects as the 
corresponding definition below:
    (i) Stationary source means any building, structure, facility, or 
installation which emits or may emit a regulated NSR pollutant.
    (ii) Building, structure, facility, or installation means all of the 
pollutant-emitting activities which belong to the same industrial 
grouping, are located on one or more contiguous or adjacent properties, 
and are under the control of the same person (or persons under common 
control) except the activities of any vessel. Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same Major Group (i.e., which have the same two-
digit code) as described in the Standard Industrial Classification 
Manual, 1972, as amended by the 1977 Supplement (U.S. Government 
Printing Office stock numbers 4101-0065 and 003-005-00176-0, 
respectively).
    (iii) Potential to emit means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant, including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
only if the limitation or the effect it would have on emissions is 
federally enforceable. Secondary emissions do not count in determining 
the potential to emit of a stationary source.
    (iv)(A) Major stationary source means:
    (1) Any stationary source of air pollutants that emits, or has the 
potential to emit, 100 tons per year or more of any regulated NSR 
pollutant, except that lower emissions thresholds shall apply in areas 
subject to subpart 2, subpart 3, or subpart 4 of part D, title I of the 
Act, according to paragraphs (a)(1)(iv)(A)(1)(i) through (vi) of this 
section.
    (i) 50 tons per year of volatile organic compounds in any serious 
ozone nonattainment area.
    (ii) 50 tons per year of volatile organic compounds in an area 
within an ozone transport region, except for any severe or extreme ozone 
nonattainment area.
    (iii) 25 tons per year of volatile organic compounds in any severe 
ozone nonattainment area.
    (iv) 10 tons per year of volatile organic compounds in any extreme 
ozone nonattainment area.
    (v) 50 tons per year of carbon monoxide in any serious nonattainment 
area for carbon monoxide, where stationary sources contribute 
significantly to carbon monoxide levels in the area (as determined under 
rules issued by the Administrator).
    (vi) 70 tons per year of PM-10 in any serious nonattainment area for 
PM-10;
    (2) For the purposes of applying the requirements of paragraph 
(a)(8) of this section to stationary sources of nitrogen oxides located 
in an ozone nonattainment area or in an ozone transport region, any 
stationary source which emits, or has the potential to emit, 100 tons 
per year or more of nitrogen oxides emissions, except that the emission 
thresholds in paragraphs (a)(1)(iv)(A)(2)(i) through (vi) of this 
section shall apply in areas subject to subpart 2 of part D, title I of 
the Act.
    (i) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as marginal or moderate.
    (ii) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as a transitional, submarginal, or 
incomplete or no data area, when such area is located in an ozone 
transport region.
    (iii) 100 tons per year or more of nitrogen oxides in any area 
designated under section 107(d) of the Act as attainment or 
unclassifiable for ozone that is located in an ozone transport region.
    (iv) 50 tons per year or more of nitrogen oxides in any serious 
nonattainment area for ozone.
    (v) 25 tons per year or more of nitrogen oxides in any severe 
nonattainment area for ozone.
    (vi) 10 tons per year or more of nitrogen oxides in any extreme 
nonattainment area for ozone; or
    (3) Any physical change that would occur at a stationary source not 
qualifying under paragraphs (a)(1)(iv)(A)(1)

[[Page 210]]

or (2) of this section as a major stationary source, if the change would 
constitute a major stationary source by itself.
    (B) A major stationary source that is major for volatile organic 
compounds shall be considered major for ozone
    (C) The fugitive emissions of a stationary source shall not be 
included in determining for any of the purposes of this paragraph 
whether it is a major stationary source, unless the source belongs to 
one of the following categories of stationary sources:
    (1) Coal cleaning plants (with thermal dryers);
    (2) Kraft pulp mills;
    (3) Portland cement plants;
    (4) Primary zinc smelters;
    (5) Iron and steel mills;
    (6) Primary aluminum ore reduction plants;
    (7) Primary copper smelters;
    (8) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (9) Hydrofluoric, sulfuric, or nitric acid plants;
    (10) Petroleum refineries;
    (11) Lime plants;
    (12) Phosphate rock processing plants;
    (13) Coke oven batteries;
    (14) Sulfur recovery plants;
    (15) Carbon black plants (furnace process);
    (16) Primary lead smelters;
    (17) Fuel conversion plants;
    (18) Sintering plants;
    (19) Secondary metal production plants;
    (20) Chemical process plants--The term chemical processing plant 
shall not include ethanol production facilities that produce ethanol by 
natural fermentation included in NAICS codes 325193 or 312140;
    (21) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (22) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (23) Taconite ore processing plants;
    (24) Glass fiber processing plants;
    (25) Charcoal production plants;
    (26) Fossil fuel-fired steam electric plants of more than 250 
million British thermal units per hour heat input; and
    (27) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.
    (v)(A) Major modification means any physical change in or change in 
the method of operation of a major stationary source that would result 
in:
    (1) A significant emissions increase of a regulated NSR pollutant 
(as defined in paragraph (a)(1)(xxxvii) of this section); and
    (2) A significant net emissions increase of that pollutant from the 
major stationary source.
    (B) Any significant emissions increase (as defined in paragraph 
(a)(1)(xxvii) of this section) from any emissions units or net emissions 
increase (as defined in paragraph (a)(1)(vi) of this section) at a major 
stationary source that is significant for volatile organic compounds 
shall be considered significant for ozone.
    (C) A physical change or change in the method of operation shall not 
include:
    (1) Routine maintenance, repair and replacement. Routine 
maintenance, repair and replacement shall include, but not be limited 
to, any activity(s) that meets the requirements of the equipment 
replacement provisions contained in paragraph (h) of this section;

    Note to paragraph (a)(1)(v)(C)(1): On December 24, 2003, the second 
sentence of this paragraph (a)(1)(v)(C)(1) is stayed indefinitely by 
court order. The stayed provisions will become effective immediately if 
the court terminates the stay. At that time, EPA will publish a document 
in the Federal Register advising the public of the termination of the 
stay.

    (2) Use of an alternative fuel or raw material by reason of an order 
under sections 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) or by reason 
of a natural gas curtailment plan pursuant to the Federal Power Act;
    (3) Use of an alternative fuel by reason of an order or rule section 
125 of the Act;
    (4) Use of an alternative fuel at a steam generating unit to the 
extent

[[Page 211]]

that the fuel is generated from municipal solid waste;
    (5) Use of an alternative fuel or raw material by a stationary 
source which;
    (i) The source was capable of accommodating before December 21, 
1976, unless such change would be prohibited under any federally 
enforceable permit condition which was established after December 12, 
1976 pursuant to 40 CFR 52.21 or under regulations approved pursuant to 
40 CFR subpart I or Sec. 51.166, or
    (ii) The source is approved to use under any permit issued under 
regulations approved pursuant to this section;
    (6) An increase in the hours of operation or in the production rate, 
unless such change is prohibited under any federally enforceable permit 
condition which was established after December 21, 1976 pursuant to 40 
CFR 52.21 or regulations approved pursuant to 40 CFR part 51 subpart I 
or 40 CFR 51.166.
    (7) Any change in ownership at a stationary source.
    (8) [Reserved]
    (9) The installation, operation, cessation, or removal of a 
temporary clean coal technology demonstration project, provided that the 
project complies with:
    (i) The State Implementation Plan for the State in which the project 
is located, and
    (ii) Other requirements necessary to attain and maintain the 
national ambient air quality standard during the project and after it is 
terminated.
    (D) This definition shall not apply with respect to a particular 
regulated NSR pollutant when the major stationary source is complying 
with the requirements under paragraph (f) of this section for a PAL for 
that pollutant. Instead, the definition at paragraph (f)(2)(viii) of 
this section shall apply.
    (E) For the purpose of applying the requirements of (a)(8) of this 
section to modifications at major stationary sources of nitrogen oxides 
located in ozone nonattainment areas or in ozone transport regions, 
whether or not subject to subpart 2, part D, title I of the Act, any 
significant net emissions increase of nitrogen oxides is considered 
significant for ozone.
    (F) Any physical change in, or change in the method of operation of, 
a major stationary source of volatile organic compounds that results in 
any increase in emissions of volatile organic compounds from any 
discrete operation, emissions unit, or other pollutant emitting activity 
at the source shall be considered a significant net emissions increase 
and a major modification for ozone, if the major stationary source is 
located in an extreme ozone nonattainment area that is subject to 
subpart 2, part D, title I of the Act.
    (G) Fugitive emissions shall not be included in determining for any 
of the purposes of this section whether a physical change in or change 
in the method of operation of a major stationary source is a major 
modification, unless the source belongs to one of the source categories 
listed in paragraph (a)(1)(iv)(C) of this section.
    (vi)(A) Net emissions increase means, with respect to any regulated 
NSR pollutant emitted by a major stationary source, the amount by which 
the sum of the following exceeds zero:
    (1) The increase in emissions from a particular physical change or 
change in the method of operation at a stationary source as calculated 
pursuant to paragraph (a)(2)(ii) of this section; and
    (2) Any other increases and decreases in actual emissions at the 
major stationary source that are contemporaneous with the particular 
change and are otherwise creditable. Baseline actual emissions for 
calculating increases and decreases under this paragraph 
(a)(1)(vi)(A)(2) shall be determined as provided in paragraph 
(a)(1)(xxxv) of this section, except that paragraphs (a)(1)(xxxv)(A)(3) 
and (a)(1)(xxxv)(B)(4) of this section shall not apply.
    (B) An increase or decrease in actual emissions is contemporaneous 
with the increase from the particular change only if it occurs before 
the date that the increase from the particular change occurs;
    (C) An increase or decrease in actual emissions is creditable only 
if:
    (1) It occurs within a reasonable period to be specified by the 
reviewing authority; and

[[Page 212]]

    (2) The reviewing authority has not relied on it in issuing a permit 
for the source under regulations approved pursuant to this section, 
which permit is in effect when the increase in actual emissions from the 
particular change occurs; and
    (3) As it pertains to an increase or decrease in fugitive emissions 
(to the extent quantifiable), it occurs at an emissions unit that is 
part of one of the source categories listed in paragraph (a)(1)(iv)(C) 
of this section or it occurs at an emissions unit that is located at a 
major stationary source that belongs to one of the listed source 
categories. Fugitive emission increases or decreases are not creditable 
for those emissions units located at a facility whose primary activity 
is not represented by one of the source categories listed in paragraph 
(a)(1)(iv)(C) of this section and that are not, by themselves, part of a 
listed source category.
    (D) An increase in actual emissions is creditable only to the extent 
that the new level of actual emissions exceeds the old level.
    (E) A decrease in actual emissions is creditable only to the extent 
that:
    (1) The old level of actual emission or the old level of allowable 
emissions whichever is lower, exceeds the new level of actual emissions;
    (2) It is enforceable as a practical matter at and after the time 
that actual construction on the particular change begins; and
    (3) The reviewing authority has not relied on it in issuing any 
permit under regulations approved pursuant to 40 CFR part 51 subpart I 
or the State has not relied on it in demonstrating attainment or 
reasonable further progress;
    (4) It has approximately the same qualitative significance for 
public health and welfare as that attributed to the increase from the 
particular change; and
    (F) An increase that results from a physical change at a source 
occurs when the emissions unit on which construction occurred becomes 
operational and begins to emit a particular pollutant. Any replacement 
unit that requires shakedown becomes operational only after a reasonable 
shakedown period, not to exceed 180 days.
    (G) Paragraph (a)(1)(xii)(B) of this section shall not apply for 
determining creditable increases and decreases or after a change.
    (vii) Emissions unit means any part of a stationary source that 
emits or would have the potential to emit any regulated NSR pollutant 
and includes an electric steam generating unit as defined in paragraph 
(a)(1)(xx) of this section. For purposes of this section, there are two 
types of emissions units as described in paragraphs (a)(1)(vii)(A) and 
(B) of this section.
    (A) A new emissions unit is any emissions unit which is (or will be) 
newly constructed and which has existed for less than 2 years from the 
date such emissions unit first operated.
    (B) An existing emissions unit is any emissions unit that does not 
meet the requirements in paragraph (a)(1)(vii)(A) of this section. A 
replacement unit, as defined in paragraph (a)(1)(xxi) of this section, 
is an existing emissions unit.
    (viii) Secondary emissons means emissions which would occur as a 
result of the construction or operation of a major stationary source or 
major modification, but do not come from the major stationary source or 
major modification itself. For the purpose of this section, secondary 
emissions must be specific, well defined, quantifiable, and impact the 
same general area as the stationary source or modification which causes 
the secondary emissions. Secondary emissions include emissions from any 
offsite support facility which would not be constructed or increase its 
emissions except as a result of the construction of operation of the 
major stationary source of major modification. Secondary emissions do 
not include any emissions which come directly from a mobile source such 
as emissions from the tailpipe of a motor vehicle, from a train, or from 
a vessel.
    (ix) Fugitive emissions means those emissions which could not 
reasonably pass through a stack, chimney, vent or other functionally 
equivalent opening. Fugitive emissions, to the extent quantifiable, are 
addressed as follows for the purposes of this section:
    (A) In determining whether a stationary source or modification is

[[Page 213]]

major, fugitive emissions from an emissions unit are included only if 
the emissions unit is part of one of the source categories listed in 
paragraph (a)(1)(iv)(C) of this section or the emissions unit is located 
at a stationary source that belongs to one of the source categories 
listed in paragraph (a)(1)(iv)(C) of this section. Fugitive emissions 
are not included for those emissions units located at a facility whose 
primary activity is not represented by one of the source categories 
listed in paragraph (a)(1)(iv)(C) of this section and that are not, by 
themselves, part of a listed source category. (See paragraphs 
(a)(1)(iv)(C) and (a)(1)(v)(G) of this section.)
    (B) For purposes of determining the net emissions increase 
associated with a project, an increase or decrease in fugitive emissions 
is creditable only if it occurs at an emissions unit that is part of one 
of the source categories listed in paragraph (a)(1)(iv)(C) of this 
section or if the emission unit is located at a major stationary source 
that belongs to one of the listed source categories. Fugitive emission 
increases or decreases are not creditable for those emissions units 
located at a facility whose primary activity is not represented by one 
of the source categories listed in paragraph (a)(1)(iv)(C) of this 
section and that are not, by themselves, part of a listed source 
category. (See paragraph (a)(1)(vi)(C)(3) of this section.)
    (C) For purposes of determining the projected actual emissions of an 
emissions unit after a project, fugitive emissions are included only if 
the emissions unit is part of one of the source categories listed in 
paragraph (a)(1)(iv)(C) of this section or if the emission unit is 
located at a major stationary source that belongs to one of the listed 
source categories. Fugitive emissions are not included for those 
emissions units located at a facility whose primary activity is not 
represented by one of the source categories listed in paragraph 
(a)(1)(iv)(C) of this section and that are not, by themselves, part of a 
listed source category. (See paragraph (a)(1)(xxviii)(B)(2) of this 
section.
    (D) For purposes of determining the baseline actual emissions of an 
emissions unit, fugitive emissions are included only if the emissions 
unit is part of one of the source categories listed in paragraph 
(a)(1)(iv)(C) of this section or if the emission unit is located at a 
major stationary source that belongs to one of the listed source 
categories, except that, for a PAL, fugitive emissions shall be included 
regardless of the source category. With the exception of PALs, fugitive 
emissions are not included for those emissions units located at a 
facility whose primary activity is not represented by one of the source 
categories listed in paragraph (a)(1)(iv)(C) of this section and that 
are not, by themselves, part of a listed source category. (See 
paragraphs (a)(1)(xxxv)(A)(1), (a)(1)(xxxv)(B)(1), (a)(1)(xxxv)(C), and 
(a)(1)(xxxv)(D) of this section.)
    (E) In calculating whether a project will cause a significant 
emissions increase, fugitive emissions are included only for those 
emissions units that are part of one of the source categories listed in 
paragraph (a)(1)(iv)(C) of this section, or for any emissions units that 
are located at a major stationary source that belongs to one of the 
listed source categories. Fugitive emissions are not included for those 
emissions units located at a facility whose primary activity is not 
represented by one of the source categories listed in paragraph 
(a)(1)(iv)(C) of this section and that are not, by themselves, part of a 
listed source category. (See paragraph (a)(2)(ii)(B) of this section.)
    (F) For purposes of monitoring and reporting emissions from a 
project after normal operations have been resumed, fugitive emissions 
are included only for those emissions units that are part of one of the 
source categories listed in paragraph (a)(1)(iv)(C) of this section, or 
for any emissions units that are located at a major stationary source 
that belongs to one of the listed source categories. Fugitive emissions 
are not included for those emissions units located at a facility whose 
primary activity is not represented by one of the source categories 
listed in paragraph (a)(1)(iv)(C) of this section and that are not, by 
themselves, part of a listed source category. (See paragraphs 
(a)(6)(iii) and (iv) of this section.)

[[Page 214]]

    (G) For all other purposes of this section, fugitive emissions are 
treated in the same manner as other, non-fugitive emissions. This 
includes, but is not limited to, the treatment of fugitive emissions for 
offsets (see paragraph (a)(3) of this section) and for PALs (see 
paragraph (f)(4)(i)(D) of this section).
    (x)(A) Significant means, in reference to a net emissions increase 
or the potential of a source to emit any of the following pollutants, a 
rate of emissions that would equal or exceed any of the following rates:

                         Pollutant Emission Rate

Carbon monoxide: 100 tons per year (tpy)
Nitrogen oxides: 40 tpy
Sulfur dioxide: 40 tpy
Ozone: 40 tpy of volatile organic compounds or nitrogen oxides
Lead: 0.6 tpy
PM10: 15 tpy
PM2.5: 10 tpy of direct PM2.5 emissions; 40 tpy of 
sulfur dioxide emissions; 40 tpy of nitrogen oxide emissions unless 
demonstrated not to be a PM2.5 precursor under paragraph 
(a)(1)(xxxvii) of this section

    (B) Notwithstanding the significant emissions rate for ozone in 
paragraph (a)(1)(x)(A) of this section, significant means, in reference 
to an emissions increase or a net emissions increase, any increase in 
actual emissions of volatile organic compounds that would result from 
any physical change in, or change in the method of operation of, a major 
stationary source locating in a serious or severe ozone nonattainment 
area that is subject to subpart 2, part D, title I of the Act, if such 
emissions increase of volatile organic compounds exceeds 25 tons per 
year.
    (C) For the purposes of applying the requirements of paragraph 
(a)(8) of this section to modifications at major stationary sources of 
nitrogen oxides located in an ozone nonattainment area or in an ozone 
transport region, the significant emission rates and other requirements 
for volatile organic compounds in paragraphs (a)(1)(x)(A), (B), and (E) 
of this section shall apply to nitrogen oxides emissions.
    (D) Notwithstanding the significant emissions rate for carbon 
monoxide under paragraph (a)(1)(x)(A) of this section, significant 
means, in reference to an emissions increase or a net emissions 
increase, any increase in actual emissions of carbon monoxide that would 
result from any physical change in, or change in the method of operation 
of, a major stationary source in a serious nonattainment area for carbon 
monoxide if such increase equals or exceeds 50 tons per year, provided 
the Administrator has determined that stationary sources contribute 
significantly to carbon monoxide levels in that area.
    (E) Notwithstanding the significant emissions rates for ozone under 
paragraphs (a)(1)(x)(A) and (B) of this section, any increase in actual 
emissions of volatile organic compounds from any emissions unit at a 
major stationary source of volatile organic compounds located in an 
extreme ozone nonattainment area that is subject to subpart 2, part D, 
title I of the Act shall be considered a significant net emissions 
increase.

    (xi) Allowable emissions means the emissions rate of a stationary 
source calculated using the maximum rated capacity of the source (unless 
the source is subject to federally enforceable limits which restrict the 
operating rate, or hours of operation, or both) and the most stringent 
of the following:
    (A) The applicable standards set forth in 40 CFR part 60 or 61;
    (B) Any applicable State Implementation Plan emissions limitation 
including those with a future compliance date; or
    (C) The emissions rate specified as a federally enforceable permit 
condition, including those with a future compliance date.
    (xii)(A) Actual emissions means the actual rate of emissions of a 
regulated NSR pollutant from an emissions unit, as determined in 
accordance with paragraphs (a)(1)(xii)(B) through (D) of this section, 
except that this definition shall not apply for calculating whether a 
significant emissions increase has occurred, or for establishing a PAL 
under paragraph (f) of this section. Instead, paragraphs (a)(1)(xxviii) 
and (xxxv) of this section shall apply for those purposes.
    (B) In general, actual emissions as of a particular date shall equal 
the average rate, in tons per year, at which the unit actually emitted 
the pollutant

[[Page 215]]

during a consecutive 24-month period which precedes the particular date 
and which is representative of normal source operation. The reviewing 
authority shall allow the use of a different time period upon a 
determination that it is more representative of normal source operation. 
Actual emissions shall be calculated using the unit's actual operating 
hours, production rates, and types of materials processed, stored, or 
combusted during the selected time period.
    (C) The reviewing authority may presume that source-specific 
allowable emissions for the unit are equivalent to the actual emissions 
of the unit.
    (D) For any emissions unit that has not begun normal operations on 
the particular date, actual emissions shall equal the potential to emit 
of the unit on that date.
    (xiii) Lowest achievable emission rate (LAER) means, for any source, 
the more stringent rate of emissions based on the following:
    (A) The most stringent emissions limitation which is contained in 
the implementation plan of any State for such class or category of 
stationary source, unless the owner or operator of the proposed 
stationary source demonstrates that such limitations are not achievable; 
or
    (B) The most stringent emissions limitation which is achieved in 
practice by such class or category of stationary sources. This 
limitation, when applied to a modification, means the lowest achievable 
emissions rate for the new or modified emissions units within or 
stationary source. In no event shall the application of the term permit 
a proposed new or modified stationary source to emit any pollutant in 
excess of the amount allowable under an applicable new source standard 
of performance.
    (xiv) Federally enforceable means all limitations and conditions 
which are enforceable by the Administrator, including those requirements 
developed pursuant to 40 CFR parts 60 and 61, requirements within any 
applicable State implementation plan, any permit requirements 
established pursuant to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR part 51, subpart I, including operating permits 
issued under an EPA-approved program that is incorporated into the State 
implementation plan and expressly requires adherence to any permit 
issued under such program.
    (xv) Begin actual construction means in general, initiation of 
physical on-site construction activities on an emissions unit which are 
of a permanent nature. Such activities include, but are not limited to, 
installation of building supports and foundations, laying of underground 
pipework, and construction of permanent storage structures. With respect 
to a change in method of operating this term refers to those on-site 
activities other than preparatory activities which mark the initiation 
of the change.
    (xvi) Commence as applied to construction of a major stationary 
source or major modification means that the owner or operator has all 
necessary preconstruction approvals or permits and either has:
    (A) Begun, or caused to begin, a continuous program of actual on-
site construction of the source, to be completed within a reasonable 
time; or
    (B) Entered into binding agreements or contractual obligations, 
which cannot be canceled or modified without substantial loss to the 
owner or operator, to undertake a program of actual construction of the 
source to be completed within a reasonable time.
    (xvii) Necessary preconstruction approvals or permits means those 
Federal air quality control laws and regulations and those air quality 
control laws and regulations which are part of the applicable State 
Implementation Plan.
    (xviii) Construction means any physical change or change in the 
method of operation (including fabrication, erection, installation, 
demolition, or modification of an emissions unit) that would result in a 
change in emissions.
    (xix)Volatile organic compounds (VOC) is as defined in Sec. 
51.100(s) of this part.
    (xx) Electric utility steam generating unit means any steam electric 
generating unit that is constructed for the purpose of supplying more 
than one-third of its potential electric output capacity and more than 
25 MW electrical output to any utility power distribution system for 
sale. Any steam

[[Page 216]]

supplied to a steam distribution system for the purpose of providing 
steam to a steam-electric generator that would produce electrical energy 
for sale is also considered in determining the electrical energy output 
capacity of the affected facility.
    (xxi) Replacement unit means an emissions unit for which all the 
criteria listed in paragraphs (a)(1)(xxi)(A) through (D) of this section 
are met. No creditable emission reductions shall be generated from 
shutting down the existing emissions unit that is replaced.
    (A) The emissions unit is a reconstructed unit within the meaning of 
Sec. 60.15(b)(1) of this chapter, or the emissions unit completely 
takes the place of an existing emissions unit.
    (B) The emissions unit is identical to or functionally equivalent to 
the replaced emissions unit.
    (C) The replacement does not alter the basic design parameters (as 
discussed in paragraph (h)(2) of this section) of the process unit.
    (D) The replaced emissions unit is permanently removed from the 
major stationary source, otherwise permanently disabled, or permanently 
barred from operation by a permit that is enforceable as a practical 
matter. If the replaced emissions unit is brought back into operation, 
it shall constitute a new emissions unit.
    (xxii) Temporary clean coal technology demonstration project means a 
clean coal technology demonstration project that is operated for a 
period of 5 years or less, and which complies with the State 
Implementation Plan for the State in which the project is located and 
other requirements necessary to attain and maintain the national ambient 
air quality standards during the project and after it is terminated.
    (xxiii) Clean coal technology means any technology, including 
technologies applied at the precombustion, combustion, or post 
combustion stage, at a new or existing facility which will achieve 
significant reductions in air emissions of sulfur dioxide or oxides of 
nitrogen associated with the utilization of coal in the generation of 
electricity, or process steam which was not in widespread use as of 
November 15, 1990.
    (xxiv) Clean coal technology demonstration project means a project 
using funds appropriated under the heading ``Department of Energy-Clean 
Coal Technology,'' up to a total amount of $2,500,000,000 for commercial 
demonstration of clean coal technology, or similar projects funded 
through appropriations for the Environmental Protection Agency. The 
Federal contribution for a qualifying project shall be at least 20 
percent of the total cost of the demonstration project.
    (xxv) [Reserved]
    (xxvi) Pollution prevention means any activity that through process 
changes, product reformulation or redesign, or substitution of less 
polluting raw materials, eliminates or reduces the release of air 
pollutants (including fugitive emissions) and other pollutants to the 
environment prior to recycling, treatment, or disposal; it does not mean 
recycling (other than certain ``in-process recycling'' practices), 
energy recovery, treatment, or disposal.
    (xxvii) Significant emissions increase means, for a regulated NSR 
pollutant, an increase in emissions that is significant (as defined in 
paragraph (a)(1)(x) of this section) for that pollutant.
    (xxviii)(A) Projected actual emissions means, the maximum annual 
rate, in tons per year, at which an existing emissions unit is projected 
to emit a regulated NSR pollutant in any one of the 5 years (12-month 
period) following the date the unit resumes regular operation after the 
project, or in any one of the 10 years following that date, if the 
project involves increasing the emissions unit's design capacity or its 
potential to emit of that regulated NSR pollutant and full utilization 
of the unit would result in a significant emissions increase or a 
significant net emissions increase at the major stationary source.
    (B) In determining the projected actual emissions under paragraph 
(a)(1)(xxviii)(A) of this section before beginning actual construction, 
the owner or operator of the major stationary source:
    (1) Shall consider all relevant information, including but not 
limited to, historical operational data, the company's own 
representations, the company's expected business activity and

[[Page 217]]

the company's highest projections of business activity, the company's 
filings with the State or Federal regulatory authorities, and compliance 
plans under the approved plan; and
    (2) Shall include emissions associated with startups, shutdowns, and 
malfunctions; and, for an emissions unit that is part of one of the 
source categories listed in paragraph (a)(1)(iv)(C) of this section or 
for an emissions unit that is located at a major stationary source that 
belongs to one of the listed source categories, shall include fugitive 
emissions (to the extent quantifiable); and
    (3) Shall exclude, in calculating any increase in emissions that 
results from the particular project, that portion of the unit's 
emissions following the project that an existing unit could have 
accommodated during the consecutive 24-month period used to establish 
the baseline actual emissions under paragraph (a)(1)(xxxv) of this 
section and that are also unrelated to the particular project, including 
any increased utilization due to product demand growth; or,
    (4) In lieu of using the method set out in paragraphs 
(a)(1)(xxviii)(B)(1) through (3) of this section, may elect to use the 
emissions unit's potential to emit, in tons per year, as defined under 
paragraph (a)(1)(iii) of this section. For this purpose, if the 
emissions unit is part of one of the source categories listed in 
paragraph (a)(1)(iv)(C) of this section or if the emissions unit is 
located at a major stationary source that belongs to one of the listed 
source categories, the unit's potential to emit shall include fugitive 
emissions (to the extent quantifiable).
    (xxix) [Reserved]
    (xxx) Nonattainment major new source review (NSR) program means a 
major source preconstruction permit program that has been approved by 
the Administrator and incorporated into the plan to implement the 
requirements of this section, or a program that implements part 51, 
appendix S, Sections I through VI of this chapter. Any permit issued 
under such a program is a major NSR permit.
    (xxxi) Continuous emissions monitoring system (CEMS) means all of 
the equipment that may be required to meet the data acquisition and 
availability requirements of this section, to sample, condition (if 
applicable), analyze, and provide a record of emissions on a continuous 
basis.
    (xxxii) Predictive emissions monitoring system (PEMS) means all of 
the equipment necessary to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O2 or CO2 concentrations), and calculate and 
record the mass emissions rate (for example, lb/hr) on a continuous 
basis.
    (xxxiii) Continuous parameter monitoring system (CPMS) means all of 
the equipment necessary to meet the data acquisition and availability 
requirements of this section, to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O2 or CO2 concentrations), and to record 
average operational parameter value(s) on a continuous basis.
    (xxxiv) Continuous emissions rate monitoring system (CERMS) means 
the total equipment required for the determination and recording of the 
pollutant mass emissions rate (in terms of mass per unit of time).
    (xxxv) Baseline actual emissions means the rate of emissions, in 
tons per year, of a regulated NSR pollutant, as determined in accordance 
with paragraphs (a)(1)(xxxv)(A) through (D) of this section.
    (A) For any existing electric utility steam generating unit, 
baseline actual emissions means the average rate, in tons per year, at 
which the unit actually emitted the pollutant during any consecutive 24-
month period selected by the owner or operator within the 5-year period 
immediately preceding when the owner or operator begins actual 
construction of the project. The reviewing authority shall allow the use 
of a different time period upon a determination that it is more 
representative of normal source operation.
    (1) The average rate shall include emissions associated with 
startups, shutdowns, and malfunctions; and, for an emissions unit that 
is part of one of

[[Page 218]]

the source categories listed in paragraph (a)(1)(iv)(C) of this section 
or for an emissions unit that is located at a major stationary source 
that belongs to one of the listed source categories, shall include 
fugitive emissions (to the extent quantifiable).
    (2) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
any emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (3) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used for each 
regulated NSR pollutant.
    (4) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraph (a)(1)(xxxv)(A)(2) of this section.
    (B) For an existing emissions unit (other than an electric utility 
steam generating unit), baseline actual emissions means the average 
rate, in tons per year, at which the emissions unit actually emitted the 
pollutant during any consecutive 24-month period selected by the owner 
or operator within the 10-year period immediately preceding either the 
date the owner or operator begins actual construction of the project, or 
the date a complete permit application is received by the reviewing 
authority for a permit required either under this section or under a 
plan approved by the Administrator, whichever is earlier, except that 
the 10-year period shall not include any period earlier than November 
15, 1990.
    (1) The average rate shall include emissions associated with 
startups, shutdowns, and malfunctions; and, for an emissions unit that 
is part of one of the source categories listed in paragraph 
(a)(1)(iv)(C) of this section or for an emissions unit that is located 
at a major stationary source that belongs to one of the listed source 
categories, shall include fugitive emissions (to the extent 
quantifiable).
    (2) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (3) The average rate shall be adjusted downward to exclude any 
emissions that would have exceeded an emission limitation with which the 
major stationary source must currently comply, had such major stationary 
source been required to comply with such limitations during the 
consecutive 24-month period. However, if an emission limitation is part 
of a maximum achievable control technology standard that the 
Administrator proposed or promulgated under part 63 of this chapter, the 
baseline actual emissions need only be adjusted if the State has taken 
credit for such emissions reductions in an attainment demonstration or 
maintenance plan consistent with the requirements of paragraph 
(a)(3)(ii)(G) of this section.
    (4) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used For each 
regulated NSR pollutant.
    (5) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraphs (a)(1)(xxxv)(B)(2) and (3) of this section.
    (C) For a new emissions unit, the baseline actual emissions for 
purposes of determining the emissions increase that will result from the 
initial construction and operation of such unit shall equal zero; and 
thereafter, for all other purposes, shall equal the unit's potential to 
emit. In the latter case, fugitive emissions, to the extent 
quantifiable, shall be included only if the emissions unit is part of 
one of the source categories listed in paragraph (a)(1)(iv)(C) of this 
section or if the

[[Page 219]]

emissions unit is located at a major stationary source that belongs to 
one of the listed source categories.
    (D) For a PAL for a major stationary source, the baseline actual 
emissions shall be calculated for existing electric utility steam 
generating units in accordance with the procedures contained in 
paragraph (a)(1)(xxxv)(A) of this section, for other existing emissions 
units in accordance with the procedures contained in paragraph 
(a)(1)(xxxv)(B) of this section, and for a new emissions unit in 
accordance with the procedures contained in paragraph (a)(1)(xxxv)(C) of 
this section, except that fugitive emissions (to the extent 
quantifiable) shall be included regardless of the source category.
    (xxxvi) [Reserved]
    (xxxvii) Regulated NSR pollutant, for purposes of this section, 
means the following:
    (A) Nitrogen oxides or any volatile organic compounds;
    (B) Any pollutant for which a national ambient air quality standard 
has been promulgated;
    (C) Any pollutant that is identified under this paragraph 
(a)(1)(xxxvii)(C) as a constituent or precursor of a general pollutant 
listed under paragraph (a)(1)(xxxvii)(A) or (B) of this section, 
provided that such constituent or precursor pollutant may only be 
regulated under NSR as part of regulation of the general pollutant. 
Precursors identified by the Administrator for purposes of NSR are the 
following:
    (1) Volatile organic compounds and nitrogen oxides are precursors to 
ozone in all ozone nonattainment areas.
    (2) Sulfur dioxide is a precursor to PM2.5 in all 
PM2.5 nonattainment areas.
    (3) Nitrogen oxides are presumed to be precursors to 
PM2.5 in all PM2.5 nonattainment areas, unless the 
State demonstrates to the Administrator's satisfaction or EPA 
demonstrates that emissions of nitrogen oxides from sources in a 
specific area are not a significant contributor to that area's ambient 
PM2.5 concentrations.
    (4) Volatile organic compounds and ammonia are presumed not to be 
precursors to PM2.5 in any PM2.5 nonattainment 
area, unless the State demonstrates to the Administrator's satisfaction 
or EPA demonstrates that emissions of volatile organic compounds or 
ammonia from sources in a specific area are a significant contributor to 
that area's ambient PM2.5 concentrations; or
    (D) PM2.5 emissions and PM10 emissions shall 
include gaseous emissions from a source or activity which condense to 
form particulate matter at ambient temperatures. On or after January 1, 
2011 (or any earlier date established in the upcoming rulemaking 
codifying test methods), such condensable particulate matter shall be 
accounted for in applicability determinations and in establishing 
emissions limitations for PM2.5 and PM10 in 
nonattainment major NSR permits. Compliance with emissions limitations 
for PM2.5 and PM10 issued prior to this date shall 
not be based on condensable particulate matter unless required by the 
terms and conditions of the permit or the applicable implementation 
plan. Applicability determinations made prior to this date without 
accounting for condensable particulate matter shall not be considered in 
violation of this section unless the applicable implementation plan 
required condensable particulate matter to be included.
    (xxxviii) Reviewing authority means the State air pollution control 
agency, local agency, other State agency, Indian tribe, or other agency 
authorized by the Administrator to carry out a permit program under this 
section and Sec. 51.166, or the Administrator in the case of EPA-
implemented permit programs under Sec. 52.21.
    (xxxix) Project means a physical change in, or change in the method 
of operation of, an existing major stationary source.
    (xl) Best available control technology (BACT) means an emissions 
limitation (including a visible emissions standard) based on the maximum 
degree of reduction for each regulated NSR pollutant which would be 
emitted from any proposed major stationary source or major modification 
which the reviewing authority, on a case-by-case basis, taking into 
account energy, environmental, and economic impacts and other costs, 
determines is achievable for such

[[Page 220]]

source or modification through application of production processes or 
available methods, systems, and techniques, including fuel cleaning or 
treatment or innovative fuel combustion techniques for control of such 
pollutant. In no event shall application of best available control 
technology result in emissions of any pollutant which would exceed the 
emissions allowed by any applicable standard under 40 CFR part 60 or 61. 
If the reviewing authority determines that technological or economic 
limitations on the application of measurement methodology to a 
particular emissions unit would make the imposition of an emissions 
standard infeasible, a design, equipment, work practice, operational 
standard, or combination thereof, may be prescribed instead to satisfy 
the requirement for the application of BACT. Such standard shall, to the 
degree possible, set forth the emissions reduction achievable by 
implementation of such design, equipment, work practice or operation, 
and shall provide for compliance by means which achieve equivalent 
results.
    (xli) Prevention of Significant Deterioration (PSD) permit means any 
permit that is issued under a major source preconstruction permit 
program that has been approved by the Administrator and incorporated 
into the plan to implement the requirements of Sec. 51.166 of this 
chapter, or under the program in Sec. 52.21 of this chapter.
    (xlii) Federal Land Manager means, with respect to any lands in the 
United States, the Secretary of the department with authority over such 
lands.
    (xliii)(A) In general, process unit means any collection of 
structures and/or equipment that processes, assembles, applies, blends, 
or otherwise uses material inputs to produce or store an intermediate or 
a completed product. A single stationary source may contain more than 
one process unit, and a process unit may contain more than one emissions 
unit.
    (B) Pollution control equipment is not part of the process unit, 
unless it serves a dual function as both process and control equipment. 
Administrative and warehousing facilities are not part of the process 
unit.
    (C) For replacement cost purposes, components shared between two or 
more process units are proportionately allocated based on capacity.
    (D) The following list identifies the process units at specific 
categories of stationary sources.
    (1) For a steam electric generating facility, the process unit 
consists of those portions of the plant that contribute directly to the 
production of electricity. For example, at a pulverized coal-fired 
facility, the process unit would generally be the combination of those 
systems from the coal receiving equipment through the emission stack 
(excluding post-combustion pollution controls), including the coal 
handling equipment, pulverizers or coal crushers, feedwater heaters, ash 
handling, boiler, burners, turbine-generator set, condenser, cooling 
tower, water treatment system, air preheaters, and operating control 
systems. Each separate generating unit is a separate process unit.
    (2) For a petroleum refinery, there are several categories of 
process units: those that separate and/or distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as steam generators and hydrogen production 
units; and those that load, unload, blend or store intermediate or 
completed products.
    (3) For an incinerator, the process unit would consist of components 
from the feed pit or refuse pit to the stack, including conveyors, 
combustion devices, heat exchangers and steam generators, quench tanks, 
and fans.

    Note to paragraph (a)(1)(xliii): By a court order on December 24, 
2003, this paragraph (a)(1)(xliii) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.

    (xliv) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.

    Note to paragraph (a)(1)(xliv): By a court order on December 24, 
2003, this paragraph (a)(1)(xliv) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the

[[Page 221]]

Federal Register advising the public of the termination of the stay.

    (xlv) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (a)(1)(xlvi) of this section.

    Note to paragraph (a)(1)(xlv): By a court order on December 24, 
2003, this paragraph (a)(1)(xlv) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.

    (xlvi) Total capital investment means the sum of the following: All 
costs required to purchase needed process equipment (purchased equipment 
costs); the costs of labor and materials for installing that equipment 
(direct installation costs); the costs of site preparation and 
buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.

    Note to paragraph (a)(1)(xlvi): By a court order on December 24, 
2003, this paragraph (a)(1)(xlvi) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.

    (2) Applicability procedures. (i) Each plan shall adopt a 
preconstruction review program to satisfy the requirements of sections 
172(c)(5) and 173 of the Act for any area designated nonattainment for 
any national ambient air quality standard under subpart C of 40 CFR part 
81. Such a program shall apply to any new major stationary source or 
major modification that is major for the pollutant for which the area is 
designated nonattainment under section 107(d)(1)(A)(i) of the Act, if 
the stationary source or modification would locate anywhere in the 
designated nonattainment area.
    (ii) Each plan shall use the specific provisions of paragraphs 
(a)(2)(ii)(A) through (F) of this section. Deviations from these 
provisions will be approved only if the State specifically demonstrates 
that the submitted provisions are more stringent than or at least as 
stringent in all respects as the corresponding provisions in paragraphs 
(a)(2)(ii)(A) through (F) of this section.
    (A) Except as otherwise provided in paragraphs (a)(2)(iii) and (iv) 
of this section, and consistent with the definition of major 
modification contained in paragraph (a)(1)(v)(A) of this section, a 
project is a major modification for a regulated NSR pollutant if it 
causes two types of emissions increases--a significant emissions 
increase (as defined in paragraph (a)(1)(xxvii) of this section), and a 
significant net emissions increase (as defined in paragraphs (a)(1)(vi) 
and (x) of this section). The project is not a major modification if it 
does not cause a significant emissions increase. If the project causes a 
significant emissions increase, then the project is a major modification 
only if it also results in a significant net emissions increase.
    (B) The procedure for calculating (before beginning actual 
construction) whether a significant emissions increase (i.e., the first 
step of the process) will occur depends upon the type of emissions units 
being modified, according to paragraphs (a)(2)(ii)(C) through (F) of 
this section. For these calculations, fugitive emissions (to the extent 
quantifiable) are included only if the emissions unit is part of one of 
the source categories listed in paragraph (a)(1)(iv)(C) of this section 
or if the emissions unit is located at a major stationary source that 
belongs to one of the listed source categories. Fugitive emissions are 
not included for those emissions units located at a facility whose 
primary activity is not represented by one of the source categories 
listed in paragraph (a)(1)(iv)(C) of this section and that are not, by 
themselves, part of a listed source category. The procedure for 
calculating (before beginning actual construction) whether a significant 
net emissions increase will occur at the major stationary source (i.e., 
the second step of

[[Page 222]]

the process) is contained in the definition in paragraph (a)(1)(vi) of 
this section. Regardless of any such preconstruction projections, a 
major modification results if the project causes a significant emissions 
increase and a significant net emissions increase.
    (C) Actual-to-projected-actual applicability test for projects that 
only involve existing emissions units. A significant emissions increase 
of a regulated NSR pollutant is projected to occur if the sum of the 
difference between the projected actual emissions (as defined in 
paragraph (a)(1)(xxviii) of this section) and the baseline actual 
emissions (as defined in paragraphs (a)(1)(xxxv)(A) and (B) of this 
section, as applicable), for each existing emissions unit, equals or 
exceeds the significant amount for that pollutant (as defined in 
paragraph (a)(1)(x) of this section).
    (D) Actual-to-potential test for projects that only involve 
construction of a new emissions unit(s). A significant emissions 
increase of a regulated NSR pollutant is projected to occur if the sum 
of the difference between the potential to emit (as defined in paragraph 
(a)(1)(iii) of this section) from each new emissions unit following 
completion of the project and the baseline actual emissions (as defined 
in paragraph (a)(1)(xxxv)(C) of this section) of these units before the 
project equals or exceeds the significant amount for that pollutant (as 
defined in paragraph (a)(1)(x) of this section).
    (E) [Reserved]
    (F) Hybrid test for projects that involve multiple types of 
emissions units. A significant emissions increase of a regulated NSR 
pollutant is projected to occur if the sum of the emissions increases 
for each emissions unit, using the method specified in paragraphs 
(a)(2)(ii)(C) through (D) of this section as applicable with respect to 
each emissions unit, for each type of emissions unit equals or exceeds 
the significant amount for that pollutant (as defined in paragraph 
(a)(1)(x) of this section).
    (iii) The plan shall require that for any major stationary source 
for a PAL for a regulated NSR pollutant, the major stationary source 
shall comply with requirements under paragraph (f) of this section.
    (3)(i) Each plan shall provide that for sources and modifications 
subject to any preconstruction review program adopted pursuant to this 
subsection the baseline for determining credit for emissions reductions 
is the emissions limit under the applicable State Implementation Plan in 
effect at the time the application to construct is filed, except that 
the offset baseline shall be the actual emissions of the source from 
which offset credit is obtained where;
    (A) The demonstration of reasonable further progress and attainment 
of ambient air quality standards is based upon the actual emissions of 
sources located within a designated nonattainment area for which the 
preconstruction review program was adopted; or
    (B) The applicable State Implementation Plan does not contain an 
emissions limitation for that source or source category.
    (ii) The plan shall further provide that:
    (A) Where the emissions limit under the applicable State 
Implementation Plan allows greater emissions than the potential to emit 
of the source, emissions offset credit will be allowed only for control 
below this potential;
    (B) For an existing fuel combustion source, credit shall be based on 
the allowable emissions under the applicable State Implementation Plan 
for the type of fuel being burned at the time the application to 
construct is filed. If the existing source commits to switch to a 
cleaner fuel at some future date, emissions offset credit based on the 
allowable (or actual) emissions for the fuels involved is not 
acceptable, unless the permit is conditioned to require the use of a 
specified alternative control measure which would achieve the same 
degree of emissions reduction should the source switch back to a dirtier 
fuel at some later date. The reviewing authority should ensure that 
adequate long-term supplies of the new fuel are available before 
granting emissions offset credit for fuel switches,
    (C)(1) Emissions reductions achieved by shutting down an existing 
emission unit or curtailing production or operating hours may be 
generally credited

[[Page 223]]

for offsets if they meet the requirements in paragraphs 
(a)(3)(ii)(C)(1)(i) through (ii) of this section.
    (i) Such reductions are surplus, permanent, quantifiable, and 
federally enforceable.
    (ii) The shutdown or curtailment occurred after the last day of the 
base year for the SIP planning process. For purposes of this paragraph, 
a reviewing authority may choose to consider a prior shutdown or 
curtailment to have occurred after the last day of the base year if the 
projected emissions inventory used to develop the attainment 
demonstration explicitly includes the emissions from such previously 
shutdown or curtailed emission units. However, in no event may credit be 
given for shutdowns that occurred before August 7, 1977.
    (2) Emissions reductions achieved by shutting down an existing 
emissions unit or curtailing production or operating hours and that do 
not meet the requirements in paragraph (a)(3)(ii)(C)(1)(ii) of this 
section may be generally credited only if:
    (i) The shutdown or curtailment occurred on or after the date the 
construction permit application is filed; or
    (ii) The applicant can establish that the proposed new emissions 
unit is a replacement for the shutdown or curtailed emissions unit, and 
the emissions reductions achieved by the shutdown or curtailment met the 
requirements of paragraph (a)(3)(ii)(C)(1)(i) of this section.
    (D) No emissions credit may be allowed for replacing one hydrocarbon 
compound with another of lesser reactivity, except for those compounds 
listed in Table 1 of EPA's ``Recommended Policy on Control of Volatile 
Organic Compounds'' (42 FR 35314, July 8, 1977; (This document is also 
available from Mr. Ted Creekmore, Office of Air Quality Planning and 
Standards, (MD-15) Research Triangle Park, NC 27711.))
    (E) All emission reductions claimed as offset credit shall be 
federally enforceable;
    (F) Procedures relating to the permissible location of offsetting 
emissions shall be followed which are at least as stringent as those set 
out in 40 CFR part 51 appendix S section IV.D.
    (G) Credit for an emissions reduction can be claimed to the extent 
that the reviewing authority has not relied on it in issuing any permit 
under regulations approved pursuant to 40 CFR part 51 subpart I or the 
State has not relied on it in demonstration attainment or reasonable 
further progress.
    (H) [Reserved]
    (I) [Reserved]
    (J) The total tonnage of increased emissions, in tons per year, 
resulting from a major modification that must be offset in accordance 
with section 173 of the Act shall be determined by summing the 
difference between the allowable emissions after the modification (as 
defined by paragraph (a)(1)(xi) of this section) and the actual 
emissions before the modification (as defined in paragraph (a)(1)(xii) 
of this section) for each emissions unit.
    (4) [Reserved]
    (5) Each plan shall include enforceable procedures to provide that:
    (i) Approval to construct shall not relieve any owner or operator of 
the responsibility to comply fully with applicable provision of the plan 
and any other requirements under local, State or Federal law.
    (ii) At such time that a particular source or modification becomes a 
major stationary source or major modification solely by virtue of a 
relaxation in any enforcement limitation which was established after 
August 7, 1980, on the capacity of the source or modification otherwise 
to emit a pollutant, such as a restriction on hours of operation, then 
the requirements of regulations approved pursuant to this section shall 
apply to the source or modification as though construction had not yet 
commenced on the source or modification;
    (6) Each plan shall provide that, except as otherwise provided in 
paragraph (a)(6)(vi) of this section, the following specific provisions 
apply with respect to any regulated NSR pollutant emitted from projects 
at existing emissions units at a major stationary source (other than 
projects at a source with a PAL) in circumstances where there is a 
reasonable possibility, within the meaning of paragraph (a)(6)(vi) of 
this section, that a project that is not

[[Page 224]]

a part of a major modification may result in a significant emissions 
increase of such pollutant, and the owner or operator elects to use the 
method specified in paragraphs (a)(1)(xxviii)(B)(1) through (3) of this 
section for calculating projected actual emissions. Deviations from 
these provisions will be approved only if the State specifically 
demonstrates that the submitted provisions are more stringent than or at 
least as stringent in all respects as the corresponding provisions in 
paragraphs (a)(6)(i) through (vi) of this section.
    (i) Before beginning actual construction of the project, the owner 
or operator shall document and maintain a record of the following 
information:
    (A) A description of the project;
    (B) Identification of the emissions unit(s) whose emissions of a 
regulated NSR pollutant could be affected by the project; and
    (C) A description of the applicability test used to determine that 
the project is not a major modification for any regulated NSR pollutant, 
including the baseline actual emissions, the projected actual emissions, 
the amount of emissions excluded under paragraph (a)(1)(xxviii)(B)(3) of 
this section and an explanation for why such amount was excluded, and 
any netting calculations, if applicable.
    (ii) If the emissions unit is an existing electric utility steam 
generating unit, before beginning actual construction, the owner or 
operator shall provide a copy of the information set out in paragraph 
(a)(6)(i) of this section to the reviewing authority. Nothing in this 
paragraph (a)(6)(ii) shall be construed to require the owner or operator 
of such a unit to obtain any determination from the reviewing authority 
before beginning actual construction.
    (iii) The owner or operator shall monitor the emissions of any 
regulated NSR pollutant that could increase as a result of the project 
and that is emitted by any emissions units identified in paragraph 
(a)(6)(i)(B) of this section; and calculate and maintain a record of the 
annual emissions, in tons per year on a calendar year basis, for a 
period of 5 years following resumption of regular operations after the 
change, or for a period of 10 years following resumption of regular 
operations after the change if the project increases the design capacity 
or potential to emit of that regulated NSR pollutant at such emissions 
unit. For purposes of this paragraph (a)(6)(iii), fugitive emissions (to 
the extent quantifiable) shall be monitored if the emissions unit is 
part of one of the source categories listed in paragraph (a)(1)(iv)(C) 
of this section or if the emissions unit is located at a major 
stationary source that belongs to one of the listed source categories.
    (iv) If the unit is an existing electric utility steam generating 
unit, the owner or operator shall submit a report to the reviewing 
authority within 60 days after the end of each year during which records 
must be generated under paragraph (a)(6)(iii) of this section setting 
out the unit's annual emissions, as monitored pursuant to paragraph 
(a)(6)(iii) of this section, during the year that preceded submission of 
the report.
    (v) If the unit is an existing unit other than an electric utility 
steam generating unit, the owner or operator shall submit a report to 
the reviewing authority if the annual emissions, in tons per year, from 
the project identified in paragraph (a)(6)(i) of this section, exceed 
the baseline actual emissions (as documented and maintained pursuant to 
paragraph (a)(6)(i)(C) of this section, by a significant amount (as 
defined in paragraph (a)(1)(x) of this section) for that regulated NSR 
pollutant, and if such emissions differ from the preconstruction 
projection as documented and maintained pursuant to paragraph 
(a)(6)(i)(C) of this section. Such report shall be submitted to the 
reviewing authority within 60 days after the end of such year. The 
report shall contain the following:
    (A) The name, address and telephone number of the major stationary 
source;
    (B) The annual emissions as calculated pursuant to paragraph 
(a)(6)(iii) of this section; and
    (C) Any other information that the owner or operator wishes to 
include in the report (e.g., an explanation as to why the emissions 
differ from the preconstruction projection).
    (vi) A ``reasonable possibility'' under paragraph (a)(6) of this 
section occurs when the owner or operator calculates the project to 
result in either:

[[Page 225]]

    (A) A projected actual emissions increase of at least 50 percent of 
the amount that is a ``significant emissions increase,'' as defined 
under paragraph (a)(1)(xxvii) of this section (without reference to the 
amount that is a significant net emissions increase), for the regulated 
NSR pollutant; or
    (B) A projected actual emissions increase that, added to the amount 
of emissions excluded under paragraph (a)(1)(xxviii)(B)(3), sums to at 
least 50 percent of the amount that is a ``significant emissions 
increase,'' as defined under paragraph (a)(1)(xxvii) of this section 
(without reference to the amount that is a significant net emissions 
increase), for the regulated NSR pollutant. For a project for which a 
reasonable possibility occurs only within the meaning of paragraph 
(a)(6)(vi)(B) of this section, and not also within the meaning of 
paragraph (a)(6)(vi)(A) of this section, then provisions (a)(6)(ii) 
through (v) do not apply to the project.
    (7) Each plan shall provide that the owner or operator of the source 
shall make the information required to be documented and maintained 
pursuant to paragraph (a)(6) of this section available for review upon a 
request for inspection by the reviewing authority or the general public 
pursuant to the requirements contained in Sec. 70.4(b)(3)(viii) of this 
chapter.
    (8) The plan shall provide that the requirements of this section 
applicable to major stationary sources and major modifications of 
volatile organic compounds shall apply to nitrogen oxides emissions from 
major stationary sources and major modifications of nitrogen oxides in 
an ozone transport region or in any ozone nonattainment area, except in 
ozone nonattainment areas or in portions of an ozone transport region 
where the Administrator has granted a NOX waiver applying the 
standards set forth under section 182(f) of the Act and the waiver 
continues to apply.
    (9)(i) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section, the ratio of total 
actual emissions reductions to the emissions increase shall be at least 
1:1 unless an alternative ratio is provided for the applicable 
nonattainment area in paragraphs (a)(9)(ii) through (a)(9)(iv) of this 
section.
    (ii) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section for ozone nonattainment 
areas that are subject to subpart 2, part D, title I of the Act, the 
ratio of total actual emissions reductions of VOC to the emissions 
increase of VOC shall be as follows:
    (A) In any marginal nonattainment area for ozone--at least 1.1:1;
    (B) In any moderate nonattainment area for ozone--at least 1.15:1;
    (C) In any serious nonattainment area for ozone--at least 1.2:1;
    (D) In any severe nonattainment area for ozone--at least 1.3:1 
(except that the ratio may be at least 1.2:1 if the approved plan also 
requires all existing major sources in such nonattainment area to use 
BACT for the control of VOC); and
    (E) In any extreme nonattainment area for ozone--at least 1.5:1 
(except that the ratio may be at least 1.2:1 if the approved plan also 
requires all existing major sources in such nonattainment area to use 
BACT for the control of VOC); and
    (iii) Notwithstanding the requirements of paragraph (a)(9)(ii) of 
this section for meeting the requirements of paragraph (a)(3) of this 
section, the ratio of total actual emissions reductions of VOC to the 
emissions increase of VOC shall be at least 1.15:1 for all areas within 
an ozone transport region that is subject to subpart 2, part D, title I 
of the Act, except for serious, severe, and extreme ozone nonattainment 
areas that are subject to subpart 2, part D, title I of the Act.
    (iv) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section for ozone nonattainment 
areas that are subject to subpart 1, part D, title I of the Act (but are 
not subject to subpart 2, part D, title I of the Act, including 8-hour 
ozone nonattainment areas subject to 40 CFR 51.902(b)), the ratio of 
total actual emissions reductions of VOC to the emissions increase of 
VOC shall be at least 1:1.
    (10) The plan shall require that the requirements of this section 
applicable

[[Page 226]]

to major stationary sources and major modifications of PM-10 shall also 
apply to major stationary sources and major modifications of PM-10 
precursors, except where the Administrator determines that such sources 
do not contribute significantly to PM-10 levels that exceed the PM-10 
ambient standards in the area.
    (11) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section, the emissions offsets 
obtained shall be for the same regulated NSR pollutant unless 
interprecursor offsetting is permitted for a particular pollutant as 
specified in this paragraph. The plan may allow the offset requirements 
in paragraph (a)(3) of this section for direct PM2.5 
emissions or emissions of precursors of PM2.5 to be satisfied 
by offsetting reductions in direct PM2.5 emissions or 
emissions of any PM2.5 precursor identified under paragraph 
(a)(1)(xxxvii)(C) of this section if such offsets comply with the 
interprecursor trading hierarchy and ratio established in the approved 
plan for a particular nonattainment area.
    (b)(1) Each plan shall include a preconstruction review permit 
program or its equivalent to satisfy the requirements of section 
110(a)(2)(D)(i) of the Act for any new major stationary source or major 
modification as defined in paragraphs (a)(1) (iv) and (v) of this 
section. Such a program shall apply to any such source or modification 
that would locate in any area designated as attainment or unclassifiable 
for any national ambient air quality standard pursuant to section 107 of 
the Act, when it would cause or contribute to a violation of any 
national ambient air quality standard.
    (2) A major source or major modification will be considered to cause 
or contribute to a violation of a national ambient air quality standard 
when such source or modification would, at a minimum, exceed the 
following significance levels at any locality that does not or would not 
meet the applicable national standard:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Averaging time (hours)
             Pollutant                       Annual         --------------------------------------------------------------------------------------------
                                                                       24                      8                      3                      1
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......  .....................  25 [micro]g/m\3\.....
PM10...............................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......
NO2................................  1.0 [micro]g/m\3\.....
CO.................................  ......................  ......................  0.5 mg/m\3\..........  .....................  2 mg/m\3\
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (3) Such a program may include a provision which allows a proposed 
major source or major modification subject to paragraph (b) of this 
section to reduce the impact of its emissions upon air quality by 
obtaining sufficient emission reductions to, at a minimum, compensate 
for its adverse ambient impact where the major source or major 
modification would otherwise cause or contribute to a violation of any 
national ambient air quality standard. The plan shall require that, in 
the absence of such emission reductions, the State or local agency shall 
deny the proposed construction.
    (4) The requirements of paragraph (b) of this section shall not 
apply to a major stationary source or major modification with respect to 
a particular pollutant if the owner or operator demonstrates that, as to 
that pollutant, the source or modification is located in an area 
designated as nonattainment pursuant to section 107 of the Act.
    (c)-(e) [Reserved]
    (f) Actuals PALs. The plan shall provide for PALs according to the 
provisions in paragraphs (f)(1) through (15) of this section.
    (1) Applicability. (i) The reviewing authority may approve the use 
of an actuals PAL for any existing major stationary source (except as 
provided in paragraph (f)(1)(ii) of this section) if the PAL meets the 
requirements in paragraphs (f)(1) through (15) of this section. The term 
``PAL'' shall mean ``actuals PAL'' throughout paragraph (f) of this 
section.
    (ii) The reviewing authority shall not allow an actuals PAL for VOC 
or NOX for any major stationary source located in an extreme 
ozone nonattainment area.

[[Page 227]]

    (iii) Any physical change in or change in the method of operation of 
a major stationary source that maintains its total source-wide emissions 
below the PAL level, meets the requirements in paragraphs (f)(1) through 
(15) of this section, and complies with the PAL permit:
    (A) Is not a major modification for the PAL pollutant;
    (B) Does not have to be approved through the plan's nonattainment 
major NSR program; and
    (C) Is not subject to the provisions in paragraph (a)(5)(ii) of this 
section (restrictions on relaxing enforceable emission limitations that 
the major stationary source used to avoid applicability of the 
nonattainment major NSR program).
    (iv) Except as provided under paragraph (f)(1)(iii)(C) of this 
section, a major stationary source shall continue to comply with all 
applicable Federal or State requirements, emission limitations, and work 
practice requirements that were established prior to the effective date 
of the PAL.
    (2) Definitions. The plan shall use the definitions in paragraphs 
(f)(2)(i) through (xi) of this section for the purpose of developing and 
implementing regulations that authorize the use of actuals PALs 
consistent with paragraphs (f)(1) through (15) of this section. When a 
term is not defined in these paragraphs, it shall have the meaning given 
in paragraph (a)(1) of this section or in the Act.
    (i) Actuals PAL for a major stationary source means a PAL based on 
the baseline actual emissions (as defined in paragraph (a)(1)(xxxv) of 
this section) of all emissions units (as defined in paragraph 
(a)(1)(vii) of this section) at the source, that emit or have the 
potential to emit the PAL pollutant.
    (ii) Allowable emissions means ``allowable emissions'' as defined in 
paragraph (a)(1)(xi) of this section, except as this definition is 
modified according to paragraphs (f)(2)(ii)(A) through (B) of this 
section.
    (A) The allowable emissions for any emissions unit shall be 
calculated considering any emission limitations that are enforceable as 
a practical matter on the emissions unit's potential to emit.
    (B) An emissions unit's potential to emit shall be determined using 
the definition in paragraph (a)(1)(iii) of this section, except that the 
words ``or enforceable as a practical matter'' should be added after 
``federally enforceable.''
    (iii) Small emissions unit means an emissions unit that emits or has 
the potential to emit the PAL pollutant in an amount less than the 
significant level for that PAL pollutant, as defined in paragraph 
(a)(1)(x) of this section or in the Act, whichever is lower.
    (iv) Major emissions unit means:
    (A) Any emissions unit that emits or has the potential to emit 100 
tons per year or more of the PAL pollutant in an attainment area; or
    (B) Any emissions unit that emits or has the potential to emit the 
PAL pollutant in an amount that is equal to or greater than the major 
source threshold for the PAL pollutant as defined by the Act for 
nonattainment areas. For example, in accordance with the definition of 
major stationary source in section 182(c) of the Act, an emissions unit 
would be a major emissions unit for VOC if the emissions unit is located 
in a serious ozone nonattainment area and it emits or has the potential 
to emit 50 or more tons of VOC per year.
    (v) Plantwide applicability limitation (PAL) means an emission 
limitation expressed in tons per year, for a pollutant at a major 
stationary source, that is enforceable as a practical matter and 
established source-wide in accordance with paragraphs (f)(1) through 
(f)(15) of this section.
    (vi) PAL effective date generally means the date of issuance of the 
PAL permit. However, the PAL effective date for an increased PAL is the 
date any emissions unit which is part of the PAL major modification 
becomes operational and begins to emit the PAL pollutant.
    (vii) PAL effective period means the period beginning with the PAL 
effective date and ending 10 years later.
    (viii) PAL major modification means, notwithstanding paragraphs 
(a)(1)(v) and (vi) of this section (the definitions for major 
modification and net emissions increase), any physical change in or 
change in the method of operation of the PAL source that causes it to 
emit

[[Page 228]]

the PAL pollutant at a level equal to or greater than the PAL.
    (ix) PAL permit means the major NSR permit, the minor NSR permit, or 
the State operating permit under a program that is approved into the 
plan, or the title V permit issued by the reviewing authority that 
establishes a PAL for a major stationary source.
    (x) PAL pollutant means the pollutant for which a PAL is established 
at a major stationary source.
    (xi) Significant emissions unit means an emissions unit that emits 
or has the potential to emit a PAL pollutant in an amount that is equal 
to or greater than the significant level (as defined in paragraph 
(a)(1)(x) of this section or in the Act, whichever is lower) for that 
PAL pollutant, but less than the amount that would qualify the unit as a 
major emissions unit as defined in paragraph (f)(2)(iv) of this section.
    (3) Permit application requirements. As part of a permit application 
requesting a PAL, the owner or operator of a major stationary source 
shall submit the following information to the reviewing authority for 
approval:
    (i) A list of all emissions units at the source designated as small, 
significant or major based on their potential to emit. In addition, the 
owner or operator of the source shall indicate which, if any, Federal or 
State applicable requirements, emission limitations or work practices 
apply to each unit.
    (ii) Calculations of the baseline actual emissions (with supporting 
documentation). Baseline actual emissions are to include emissions 
associated not only with operation of the unit, but also emissions 
associated with startup, shutdown and malfunction.
    (iii) The calculation procedures that the major stationary source 
owner or operator proposes to use to convert the monitoring system data 
to monthly emissions and annual emissions based on a 12-month rolling 
total for each month as required by paragraph (f)(13)(i) of this 
section.
    (4) General requirements for establishing PALs. (i) The plan allows 
the reviewing authority to establish a PAL at a major stationary source, 
provided that at a minimum, the requirements in paragraphs (f)(4)(i)(A) 
through (G) of this section are met.
    (A) The PAL shall impose an annual emission limitation in tons per 
year, that is enforceable as a practical matter, for the entire major 
stationary source. For each month during the PAL effective period after 
the first 12 months of establishing a PAL, the major stationary source 
owner or operator shall show that the sum of the monthly emissions from 
each emissions unit under the PAL for the previous 12 consecutive months 
is less than the PAL (a 12-month average, rolled monthly). For each 
month during the first 11 months from the PAL effective date, the major 
stationary source owner or operator shall show that the sum of the 
preceding monthly emissions from the PAL effective date for each 
emissions unit under the PAL is less than the PAL.
    (B) The PAL shall be established in a PAL permit that meets the 
public participation requirements in paragraph (f)(5) of this section.
    (C) The PAL permit shall contain all the requirements of paragraph 
(f)(7) of this section.
    (D) The PAL shall include fugitive emissions, to the extent 
quantifiable, from all emissions units that emit or have the potential 
to emit the PAL pollutant at the major stationary source, regardless of 
whether the emissions unit or major stationary source belongs to one of 
the source categories listed in paragraph (a)(1)(iv)(C) of this section.
    (E) Each PAL shall regulate emissions of only one pollutant.
    (F) Each PAL shall have a PAL effective period of 10 years.
    (G) The owner or operator of the major stationary source with a PAL 
shall comply with the monitoring, recordkeeping, and reporting 
requirements provided in paragraphs (f)(12) through (14) of this section 
for each emissions unit under the PAL through the PAL effective period.
    (ii) At no time (during or after the PAL effective period) are 
emissions reductions of a PAL pollutant, which occur during the PAL 
effective period, creditable as decreases for purposes of offsets under 
paragraph (a)(3)(ii) of this section unless the level of the PAL is 
reduced by the amount of such emissions reductions and such reductions

[[Page 229]]

would be creditable in the absence of the PAL.
    (5) Public participation requirement for PALs. PALs for existing 
major stationary sources shall be established, renewed, or increased 
through a procedure that is consistent with Sec. Sec. 51.160 and 51.161 
of this chapter. This includes the requirement that the reviewing 
authority provide the public with notice of the proposed approval of a 
PAL permit and at least a 30-day period for submittal of public comment. 
The reviewing authority must address all material comments before taking 
final action on the permit.
    (6) Setting the 10-year actuals PAL level. (i) Except as provided in 
paragraph (f)(6)(ii) of this section, the plan shall provide that the 
actuals PAL level for a major stationary source shall be established as 
the sum of the baseline actual emissions (as defined in paragraph 
(a)(1)(xxxv) of this section) of the PAL pollutant for each emissions 
unit at the source; plus an amount equal to the applicable significant 
level for the PAL pollutant under paragraph (a)(1)(x) of this section or 
under the Act, whichever is lower. When establishing the actuals PAL 
level, for a PAL pollutant, only one consecutive 24-month period must be 
used to determine the baseline actual emissions for all existing 
emissions units. However, a different consecutive 24-month period may be 
used for each different PAL pollutant. Emissions associated with units 
that were permanently shut down after this 24-month period must be 
subtracted from the PAL level. The reviewing authority shall specify a 
reduced PAL level(s) (in tons/yr) in the PAL permit to become effective 
on the future compliance date(s) of any applicable Federal or State 
regulatory requirement(s) that the reviewing authority is aware of prior 
to issuance of the PAL permit. For instance, if the source owner or 
operator will be required to reduce emissions from industrial boilers in 
half from baseline emissions of 60 ppm NOX to a new rule 
limit of 30 ppm, then the permit shall contain a future effective PAL 
level that is equal to the current PAL level reduced by half of the 
original baseline emissions of such unit(s).
    (ii) For newly constructed units (which do not include modifications 
to existing units) on which actual construction began after the 24-month 
period, in lieu of adding the baseline actual emissions as specified in 
paragraph (f)(6)(i) of this section, the emissions must be added to the 
PAL level in an amount equal to the potential to emit of the units.
    (7) Contents of the PAL permit. The plan shall require that the PAL 
permit contain, at a minimum, the information in paragraphs (f)(7)(i) 
through (x) of this section.
    (i) The PAL pollutant and the applicable source-wide emission 
limitation in tons per year.
    (ii) The PAL permit effective date and the expiration date of the 
PAL (PAL effective period).
    (iii) Specification in the PAL permit that if a major stationary 
source owner or operator applies to renew a PAL in accordance with 
paragraph (f)(10) of this section before the end of the PAL effective 
period, then the PAL shall not expire at the end of the PAL effective 
period. It shall remain in effect until a revised PAL permit is issued 
by the reviewing authority.
    (iv) A requirement that emission calculations for compliance 
purposes include emissions from startups, shutdowns and malfunctions.
    (v) A requirement that, once the PAL expires, the major stationary 
source is subject to the requirements of paragraph (f)(9) of this 
section.
    (vi) The calculation procedures that the major stationary source 
owner or operator shall use to convert the monitoring system data to 
monthly emissions and annual emissions based on a 12-month rolling total 
for each month as required by paragraph (f)(13)(i) of this section.
    (vii) A requirement that the major stationary source owner or 
operator monitor all emissions units in accordance with the provisions 
under paragraph (f)(12) of this section.
    (viii) A requirement to retain the records required under paragraph 
(f)(13) of this section on site. Such records may be retained in an 
electronic format.
    (ix) A requirement to submit the reports required under paragraph 
(f)(14)

[[Page 230]]

of this section by the required deadlines.
    (x) Any other requirements that the reviewing authority deems 
necessary to implement and enforce the PAL.
    (8) PAL effective period and reopening of the PAL permit. The plan 
shall require the information in paragraphs (f)(8)(i) and (ii) of this 
section.
    (i) PAL effective period. The reviewing authority shall specify a 
PAL effective period of 10 years.
    (ii) Reopening of the PAL permit. (A) During the PAL effective 
period, the plan shall require the reviewing authority to reopen the PAL 
permit to:
    (1) Correct typographical/calculation errors made in setting the PAL 
or reflect a more accurate determination of emissions used to establish 
the PAL.
    (2) Reduce the PAL if the owner or operator of the major stationary 
source creates creditable emissions reductions for use as offsets under 
paragraph (a)(3)(ii) of this section.
    (3) Revise the PAL to reflect an increase in the PAL as provided 
under paragraph (f)(11) of this section.
    (B) The plan shall provide the reviewing authority discretion to 
reopen the PAL permit for the following:
    (1) Reduce the PAL to reflect newly applicable Federal requirements 
(for example, NSPS) with compliance dates after the PAL effective date.
    (2) Reduce the PAL consistent with any other requirement, that is 
enforceable as a practical matter, and that the State may impose on the 
major stationary source under the plan.
    (3) Reduce the PAL if the reviewing authority determines that a 
reduction is necessary to avoid causing or contributing to a NAAQS or 
PSD increment violation, or to an adverse impact on an air quality 
related value that has been identified for a Federal Class I area by a 
Federal Land Manager and for which information is available to the 
general public.
    (C) Except for the permit reopening in paragraph (f)(8)(ii)(A)(1) of 
this section for the correction of typographical/calculation errors that 
do not increase the PAL level, all other reopenings shall be carried out 
in accordance with the public participation requirements of paragraph 
(f)(5) of this section.
    (9) Expiration of a PAL. Any PAL which is not renewed in accordance 
with the procedures in paragraph (f)(10) of this section shall expire at 
the end of the PAL effective period, and the requirements in paragraphs 
(f)(9)(i) through (v) of this section shall apply.
    (i) Each emissions unit (or each group of emissions units) that 
existed under the PAL shall comply with an allowable emission limitation 
under a revised permit established according to the procedures in 
paragraphs (f)(9)(i)(A) through (B) of this section.
    (A) Within the time frame specified for PAL renewals in paragraph 
(f)(10)(ii) of this section, the major stationary source shall submit a 
proposed allowable emission limitation for each emissions unit (or each 
group of emissions units, if such a distribution is more appropriate as 
decided by the reviewing authority) by distributing the PAL allowable 
emissions for the major stationary source among each of the emissions 
units that existed under the PAL. If the PAL had not yet been adjusted 
for an applicable requirement that became effective during the PAL 
effective period, as required under paragraph (f)(10)(v) of this 
section, such distribution shall be made as if the PAL had been 
adjusted.
    (B) The reviewing authority shall decide whether and how the PAL 
allowable emissions will be distributed and issue a revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as the reviewing authority determines is appropriate.
    (ii) Each emissions unit(s) shall comply with the allowable emission 
limitation on a 12-month rolling basis. The reviewing authority may 
approve the use of monitoring systems (source testing, emission factors, 
etc.) other than CEMS, CERMS, PEMS or CPMS to demonstrate compliance 
with the allowable emission limitation.
    (iii) Until the reviewing authority issues the revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as required under paragraph (f)(9)(i)(A) of this 
section, the source shall continue to comply with a source-wide, multi-
unit emissions cap equivalent to

[[Page 231]]

the level of the PAL emission limitation.
    (iv) Any physical change or change in the method of operation at the 
major stationary source will be subject to the nonattainment major NSR 
requirements if such change meets the definition of major modification 
in paragraph (a)(1)(v) of this section.
    (v) The major stationary source owner or operator shall continue to 
comply with any State or Federal applicable requirements (BACT, RACT, 
NSPS, etc.) that may have applied either during the PAL effective period 
or prior to the PAL effective period except for those emission 
limitations that had been established pursuant to paragraph (a)(5)(ii) 
of this section, but were eliminated by the PAL in accordance with the 
provisions in paragraph (f)(1)(iii)(C) of this section.
    (10) Renewal of a PAL. (i) The reviewing authority shall follow the 
procedures specified in paragraph (f)(5) of this section in approving 
any request to renew a PAL for a major stationary source, and shall 
provide both the proposed PAL level and a written rationale for the 
proposed PAL level to the public for review and comment. During such 
public review, any person may propose a PAL level for the source for 
consideration by the reviewing authority.
    (ii) Application deadline. The plan shall require that a major 
stationary source owner or operator shall submit a timely application to 
the reviewing authority to request renewal of a PAL. A timely 
application is one that is submitted at least 6 months prior to, but not 
earlier than 18 months from, the date of permit expiration. This 
deadline for application submittal is to ensure that the permit will not 
expire before the permit is renewed. If the owner or operator of a major 
stationary source submits a complete application to renew the PAL within 
this time period, then the PAL shall continue to be effective until the 
revised permit with the renewed PAL is issued.
    (iii) Application requirements. The application to renew a PAL 
permit shall contain the information required in paragraphs 
(f)(10)(iii)(A) through (D) of this section.
    (A) The information required in paragraphs (f)(3)(i) through (iii) 
of this section.
    (B) A proposed PAL level.
    (C) The sum of the potential to emit of all emissions units under 
the PAL (with supporting documentation).
    (D) Any other information the owner or operator wishes the reviewing 
authority to consider in determining the appropriate level for renewing 
the PAL.
    (iv) PAL adjustment. In determining whether and how to adjust the 
PAL, the reviewing authority shall consider the options outlined in 
paragraphs (f)(10)(iv)(A) and (B) of this section. However, in no case 
may any such adjustment fail to comply with paragraph (f)(10)(iv)(C) of 
this section.
    (A) If the emissions level calculated in accordance with paragraph 
(f)(6) of this section is equal to or greater than 80 percent of the PAL 
level, the reviewing authority may renew the PAL at the same level 
without considering the factors set forth in paragraph (f)(10)(iv)(B) of 
this section; or
    (B) The reviewing authority may set the PAL at a level that it 
determines to be more representative of the source's baseline actual 
emissions, or that it determines to be appropriate considering air 
quality needs, advances in control technology, anticipated economic 
growth in the area, desire to reward or encourage the source's voluntary 
emissions reductions, or other factors as specifically identified by the 
reviewing authority in its written rationale.
    (C) Notwithstanding paragraphs (f)(10)(iv)(A) and (B) of this 
section,
    (1) If the potential to emit of the major stationary source is less 
than the PAL, the reviewing authority shall adjust the PAL to a level no 
greater than the potential to emit of the source; and
    (2) The reviewing authority shall not approve a renewed PAL level 
higher than the current PAL, unless the major stationary source has 
complied with the provisions of paragraph (f)(11) of this section 
(increasing a PAL).
    (v) If the compliance date for a State or Federal requirement that 
applies to the PAL source occurs during the PAL effective period, and if 
the reviewing

[[Page 232]]

authority has not already adjusted for such requirement, the PAL shall 
be adjusted at the time of PAL permit renewal or title V permit renewal, 
whichever occurs first.
    (11) Increasing a PAL during the PAL effective period. (i) The plan 
shall require that the reviewing authority may increase a PAL emission 
limitation only if the major stationary source complies with the 
provisions in paragraphs (f)(11)(i)(A) through (D) of this section.
    (A) The owner or operator of the major stationary source shall 
submit a complete application to request an increase in the PAL limit 
for a PAL major modification. Such application shall identify the 
emissions unit(s) contributing to the increase in emissions so as to 
cause the major stationary source's emissions to equal or exceed its 
PAL.
    (B) As part of this application, the major stationary source owner 
or operator shall demonstrate that the sum of the baseline actual 
emissions of the small emissions units, plus the sum of the baseline 
actual emissions of the significant and major emissions units assuming 
application of BACT equivalent controls, plus the sum of the allowable 
emissions of the new or modified emissions unit(s) exceeds the PAL. The 
level of control that would result from BACT equivalent controls on each 
significant or major emissions unit shall be determined by conducting a 
new BACT analysis at the time the application is submitted, unless the 
emissions unit is currently required to comply with a BACT or LAER 
requirement that was established within the preceding 10 years. In such 
a case, the assumed control level for that emissions unit shall be equal 
to the level of BACT or LAER with which that emissions unit must 
currently comply.
    (C) The owner or operator obtains a major NSR permit for all 
emissions unit(s) identified in paragraph (f)(11)(i)(A) of this section, 
regardless of the magnitude of the emissions increase resulting from 
them (that is, no significant levels apply). These emissions unit(s) 
shall comply with any emissions requirements resulting from the 
nonattainment major NSR program process (for example, LAER), even though 
they have also become subject to the PAL or continue to be subject to 
the PAL.
    (D) The PAL permit shall require that the increased PAL level shall 
be effective on the day any emissions unit that is part of the PAL major 
modification becomes operational and begins to emit the PAL pollutant.
    (ii) The reviewing authority shall calculate the new PAL as the sum 
of the allowable emissions for each modified or new emissions unit, plus 
the sum of the baseline actual emissions of the significant and major 
emissions units (assuming application of BACT equivalent controls as 
determined in accordance with paragraph (f)(11)(i)(B)), plus the sum of 
the baseline actual emissions of the small emissions units.
    (iii) The PAL permit shall be revised to reflect the increased PAL 
level pursuant to the public notice requirements of paragraph (f)(5) of 
this section.
    (12) Monitoring requirements for PALs--(i) General requirements. (A) 
Each PAL permit must contain enforceable requirements for the monitoring 
system that accurately determines plantwide emissions of the PAL 
pollutant in terms of mass per unit of time. Any monitoring system 
authorized for use in the PAL permit must be based on sound science and 
meet generally acceptable scientific procedures for data quality and 
manipulation. Additionally, the information generated by such system 
must meet minimum legal requirements for admissibility in a judicial 
proceeding to enforce the PAL permit.
    (B) The PAL monitoring system must employ one or more of the four 
general monitoring approaches meeting the minimum requirements set forth 
in paragraphs (f)(12)(ii)(A) through (D) of this section and must be 
approved by the reviewing authority.
    (C) Notwithstanding paragraph (f)(12)(i)(B) of this section, you may 
also employ an alternative monitoring approach that meets paragraph 
(f)(12)(i)(A) of this section if approved by the reviewing authority.
    (D) Failure to use a monitoring system that meets the requirements 
of this section renders the PAL invalid.

[[Page 233]]

    (ii) Minimum Performance Requirements for Approved Monitoring 
Approaches. The following are acceptable general monitoring approaches 
when conducted in accordance with the minimum requirements in paragraphs 
(f)(12)(iii) through (ix) of this section:
    (A) Mass balance calculations for activities using coatings or 
solvents;
    (B) CEMS;
    (C) CPMS or PEMS; and
    (D) Emission Factors.
    (iii) Mass Balance Calculations. An owner or operator using mass 
balance calculations to monitor PAL pollutant emissions from activities 
using coating or solvents shall meet the following requirements:
    (A) Provide a demonstrated means of validating the published content 
of the PAL pollutant that is contained in or created by all materials 
used in or at the emissions unit;
    (B) Assume that the emissions unit emits all of the PAL pollutant 
that is contained in or created by any raw material or fuel used in or 
at the emissions unit, if it cannot otherwise be accounted for in the 
process; and
    (C) Where the vendor of a material or fuel, which is used in or at 
the emissions unit, publishes a range of pollutant content from such 
material, the owner or operator must use the highest value of the range 
to calculate the PAL pollutant emissions unless the reviewing authority 
determines there is site-specific data or a site-specific monitoring 
program to support another content within the range.
    (iv) CEMS. An owner or operator using CEMS to monitor PAL pollutant 
emissions shall meet the following requirements:
    (A) CEMS must comply with applicable Performance Specifications 
found in 40 CFR part 60, appendix B; and
    (B) CEMS must sample, analyze and record data at least every 15 
minutes while the emissions unit is operating.
    (v) CPMS or PEMS. An owner or operator using CPMS or PEMS to monitor 
PAL pollutant emissions shall meet the following requirements:
    (A) The CPMS or the PEMS must be based on current site-specific data 
demonstrating a correlation between the monitored parameter(s) and the 
PAL pollutant emissions across the range of operation of the emissions 
unit; and
    (B) Each CPMS or PEMS must sample, analyze, and record data at least 
every 15 minutes, or at another less frequent interval approved by the 
reviewing authority, while the emissions unit is operating.
    (vi) Emission factors. An owner or operator using emission factors 
to monitor PAL pollutant emissions shall meet the following 
requirements:
    (A) All emission factors shall be adjusted, if appropriate, to 
account for the degree of uncertainty or limitations in the factors' 
development;
    (B) The emissions unit shall operate within the designated range of 
use for the emission factor, if applicable; and
    (C) If technically practicable, the owner or operator of a 
significant emissions unit that relies on an emission factor to 
calculate PAL pollutant emissions shall conduct validation testing to 
determine a site-specific emission factor within 6 months of PAL permit 
issuance, unless the reviewing authority determines that testing is not 
required.
    (vii) A source owner or operator must record and report maximum 
potential emissions without considering enforceable emission limitations 
or operational restrictions for an emissions unit during any period of 
time that there is no monitoring data, unless another method for 
determining emissions during such periods is specified in the PAL 
permit.
    (viii) Notwithstanding the requirements in paragraphs (f)(12)(iii) 
through (vii) of this section, where an owner or operator of an 
emissions unit cannot demonstrate a correlation between the monitored 
parameter(s) and the PAL pollutant emissions rate at all operating 
points of the emissions unit, the reviewing authority shall, at the time 
of permit issuance:
    (A) Establish default value(s) for determining compliance with the 
PAL based on the highest potential emissions reasonably estimated at 
such operating point(s); or
    (B) Determine that operation of the emissions unit during operating 
conditions when there is no correlation between monitored parameter(s) 
and the

[[Page 234]]

PAL pollutant emissions is a violation of the PAL.
    (ix) Re-validation. All data used to establish the PAL pollutant 
must be re-validated through performance testing or other scientifically 
valid means approved by the reviewing authority. Such testing must occur 
at least once every 5 years after issuance of the PAL.
    (13) Recordkeeping requirements. (i) The PAL permit shall require an 
owner or operator to retain a copy of all records necessary to determine 
compliance with any requirement of paragraph (f) of this section and of 
the PAL, including a determination of each emissions unit's 12-month 
rolling total emissions, for 5 years from the date of such record.
    (ii) The PAL permit shall require an owner or operator to retain a 
copy of the following records for the duration of the PAL effective 
period plus 5 years:
    (A) A copy of the PAL permit application and any applications for 
revisions to the PAL; and
    (B) Each annual certification of compliance pursuant to title V and 
the data relied on in certifying the compliance.
    (14) Reporting and notification requirements. The owner or operator 
shall submit semi-annual monitoring reports and prompt deviation reports 
to the reviewing authority in accordance with the applicable title V 
operating permit program. The reports shall meet the requirements in 
paragraphs (f)(14)(i) through (iii).
    (i) Semi-Annual Report. The semi-annual report shall be submitted to 
the reviewing authority within 30 days of the end of each reporting 
period. This report shall contain the information required in paragraphs 
(f)(14)(i)(A) through (G) of this section.
    (A) The identification of owner and operator and the permit number.
    (B) Total annual emissions (tons/year) based on a 12-month rolling 
total for each month in the reporting period recorded pursuant to 
paragraph (f)(13)(i) of this section.
    (C) All data relied upon, including, but not limited to, any Quality 
Assurance or Quality Control data, in calculating the monthly and annual 
PAL pollutant emissions.
    (D) A list of any emissions units modified or added to the major 
stationary source during the preceding 6-month period.
    (E) The number, duration, and cause of any deviations or monitoring 
malfunctions (other than the time associated with zero and span 
calibration checks), and any corrective action taken.
    (F) A notification of a shutdown of any monitoring system, whether 
the shutdown was permanent or temporary, the reason for the shutdown, 
the anticipated date that the monitoring system will be fully 
operational or replaced with another monitoring system, and whether the 
emissions unit monitored by the monitoring system continued to operate, 
and the calculation of the emissions of the pollutant or the number 
determined by method included in the permit, as provided by paragraph 
(f)(12)(vii) of this section.
    (G) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy, and completeness of the information provided in the report.
    (ii) Deviation report. The major stationary source owner or operator 
shall promptly submit reports of any deviations or exceedance of the PAL 
requirements, including periods where no monitoring is available. A 
report submitted pursuant to Sec. 70.6(a)(3)(iii)(B) of this chapter 
shall satisfy this reporting requirement. The deviation reports shall be 
submitted within the time limits prescribed by the applicable program 
implementing Sec. 70.6(a)(3)(iii)(B) of this chapter. The reports shall 
contain the following information:
    (A) The identification of owner and operator and the permit number;
    (B) The PAL requirement that experienced the deviation or that was 
exceeded;
    (C) Emissions resulting from the deviation or the exceedance; and
    (D) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy,

[[Page 235]]

and completeness of the information provided in the report.
    (iii) Re-validation results. The owner or operator shall submit to 
the reviewing authority the results of any re-validation test or method 
within 3 months after completion of such test or method.
    (15) Transition requirements. (i) No reviewing authority may issue a 
PAL that does not comply with the requirements in paragraphs (f)(1) 
through (15) of this section after the Administrator has approved 
regulations incorporating these requirements into a plan.
    (ii) The reviewing authority may supersede any PAL which was 
established prior to the date of approval of the plan by the 
Administrator with a PAL that complies with the requirements of 
paragraphs (f)(1) through (15) of this section.
    (g) If any provision of this section, or the application of such 
provision to any person or circumstance, is held invalid, the remainder 
of this section, or the application of such provision to persons or 
circumstances other than those as to which it is held invalid, shall not 
be affected thereby.
    (h) Equipment replacement provision. Without regard to other 
considerations, routine maintenance, repair and replacement includes, 
but is not limited to, the replacement of any component of a process 
unit with an identical or functionally equivalent component(s), and 
maintenance and repair activities that are part of the replacement 
activity, provided that all of the requirements in paragraphs (h)(1) 
through (3) of this section are met.
    (1) Capital Cost threshold for Equipment Replacement. (i) For an 
electric utility steam generating unit, as defined in Sec. 
51.165(a)(1)(xx), the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced. For a process unit that is not an electric utility steam 
generating unit the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced.
    (ii) In determining the replacement value of the process unit; and, 
except as otherwise allowed under paragraph (h)(1)(iii) of this section, 
the owner or operator shall determine the replacement value of the 
process unit on an estimate of the fixed capital cost of constructing a 
new process unit, or on the current appraised value of the process unit.
    (iii) As an alternative to paragraph (h)(1)(ii) of this section for 
determining the replacement value of a process unit, an owner or 
operator may choose to use insurance value (where the insurance value 
covers only complete replacement), investment value adjusted for 
inflation, or another accounting procedure if such procedure is based on 
Generally Accepted Accounting Principles, provided that the owner or 
operator sends a notice to the reviewing authority. The first time that 
an owner or operator submits such a notice for a particular process 
unit, the notice may be submitted at any time, but any subsequent notice 
for that process unit may be submitted only at the beginning of the 
process unit's fiscal year. Unless the owner or operator submits a 
notice to the reviewing authority, then paragraph (h)(1)(ii) of this 
section will be used to establish the replacement value of the process 
unit. Once the owner or operator submits a notice to use an alternative 
accounting procedure, the owner or operator must continue to use that 
procedure for the entire fiscal year for that process unit. In 
subsequent fiscal years, the owner or operator must continue to use this 
selected procedure unless and until the owner or operator sends another 
notice to the reviewing authority selecting another procedure consistent 
with this paragraph or paragraph (h)(1)(ii) of this section at the 
beginning of such fiscal year.
    (2) Basic design parameters. The replacement does not change the 
basic design parameter(s) of the process unit to which the activity 
pertains.

    Note to paragraph (h): By a court order on December 24, 2003, this 
paragraph (h) is stayed indefinitely. The stayed provisions will become 
effective immediately if the

[[Page 236]]

court terminates the stay. At that time, EPA will publish a document in 
the Federal Register advising the public of the termination of the stay.

    (i) Except as provided in paragraph (h)(2)(iii) of this section, for 
a process unit at a steam electric generating facility, the owner or 
operator may select as its basic design parameters either maximum hourly 
heat input and maximum hourly fuel consumption rate or maximum hourly 
electric output rate and maximum steam flow rate. When establishing fuel 
consumption specifications in terms of weight or volume, the minimum 
fuel quality based on British Thermal Units content shall be used for 
determining the basic design parameter(s) for a coal-fired electric 
utility steam generating unit.
    (ii) Except as provided in paragraph (h)(2)(iii) of this section, 
the basic design parameter(s) for any process unit that is not at a 
steam electric generating facility are maximum rate of fuel or heat 
input, maximum rate of material input, or maximum rate of product 
output. Combustion process units will typically use maximum rate of fuel 
input. For sources having multiple end products and raw materials, the 
owner or operator should consider the primary product or primary raw 
material when selecting a basic design parameter.
    (iii) If the owner or operator believes the basic design 
parameter(s) in paragraphs (h)(2)(i) and (ii) of this section is not 
appropriate for a specific industry or type of process unit, the owner 
or operator may propose to the reviewing authority an alternative basic 
design parameter(s) for the source's process unit(s). If the reviewing 
authority approves of the use of an alternative basic design 
parameter(s), the reviewing authority shall issue a permit that is 
legally enforceable that records such basic design parameter(s) and 
requires the owner or operator to comply with such parameter(s).
    (iv) The owner or operator shall use credible information, such as 
results of historic maximum capability tests, design information from 
the manufacturer, or engineering calculations, in establishing the 
magnitude of the basic design parameter(s) specified in paragraphs 
(h)(2)(i) and (ii) of this section.
    (v) If design information is not available for a process unit, then 
the owner or operator shall determine the process unit's basic design 
parameter(s) using the maximum value achieved by the process unit in the 
five-year period immediately preceding the planned activity.
    (vi) Efficiency of a process unit is not a basic design parameter.
    (3) The replacement activity shall not cause the process unit to 
exceed any emission limitation, or operational limitation that has the 
effect of constraining emissions, that applies to the process unit and 
that is legally enforceable.

[51 FR 40669, Nov. 7, 1986, as amended at 52 FR 24713, July 1, 1987; 52 
FR 29386, Aug 7, 1987; 54 FR 27285, 27299 June 28, 1989; 57 FR 3946, 
Feb. 3, 1992; 57 FR 32334, July 21, 1992; 67 FR 80244, Dec. 31, 2002; 68 
FR 61276, Oct. 27, 2003; 68 FR 63027, Nov. 7, 2003; 69 FR 40275, July 1, 
2004; 70 FR 71698, Nov. 29, 2005; 72 FR 24077, May 1, 2007; 72 FR 32528, 
June 13, 2007; 72 FR 72616, Dec. 21, 2007; 73 FR 28347, May 16, 2008; 73 
FR 77895, Dec. 19, 2008]



Sec. 51.166  Prevention of significant deterioration of air quality.

    (a)(1) Plan requirements. In accordance with the policy of section 
101(b)(1) of the Act and the purposes of section 160 of the Act, each 
applicable State Implementation Plan and each applicable Tribal 
Implementation Plan shall contain emission limitations and such other 
measures as may be necessary to prevent significant deterioration of air 
quality.
    (2) Plan revisions. If a State Implementation Plan revision would 
result in increased air quality deterioration over any baseline 
concentration, the plan revision shall include a demonstration that it 
will not cause or contribute to a violation of the applicable 
increment(s). If a plan revision proposing less restrictive requirements 
was submitted after August 7, 1977 but on or before any applicable 
baseline date and was pending action by the Administrator on that date, 
no such demonstration is necessary with respect to the area for which a 
baseline date would be established before final action is taken on the 
plan revision. Instead, the assessment described in paragraph

[[Page 237]]

(a)(4) of this section, shall review the expected impact to the 
applicable increment(s).
    (3) Required plan revision. If the State or the Administrator 
determines that a plan is substantially inadequate to prevent 
significant deterioration or that an applicable increment is being 
violated, the plan shall be revised to correct the inadequacy or the 
violation. The plan shall be revised within 60 days of such a finding by 
a State or within 60 days following notification by the Administrator, 
or by such later date as prescribed by the Administrator after 
consultation with the State.
    (4) Plan assessment. The State shall review the adequacy of a plan 
on a periodic basis and within 60 days of such time as information 
becomes available that an applicable increment is being violated.
    (5) Public participation. Any State action taken under this 
paragraph shall be subject to the opportunity for public hearing in 
accordance with procedures equivalent to those established in Sec. 
51.102.
    (6) Amendments. (i) Any State required to revise its implementation 
plan by reason of an amendment to this section, including any amendment 
adopted simultaneously with this paragraph (a)(6)(i), shall adopt and 
submit such plan revision to the Administrator for approval no later 
than three years after such amendment is published in the Federal 
Register.
    (ii) Any revision to an implementation plan that would amend the 
provisions for the prevention of significant air quality deterioration 
in the plan shall specify when and as to what sources and modifications 
the revision is to take effect.
    (iii) Any revision to an implementation plan that an amendment to 
this section required shall take effect no later than the date of its 
approval and may operate prospectively.
    (7) Applicability. Each plan shall contain procedures that 
incorporate the requirements in paragraphs (a)(7)(i) through (vi) of 
this section.
    (i) The requirements of this section apply to the construction of 
any new major stationary source (as defined in paragraph (b)(1) of this 
section) or any project at an existing major stationary source in an 
area designated as attainment or unclassifiable under sections 
107(d)(1)(A)(ii) or (iii) of the Act.
    (ii) The requirements of paragraphs (j) through (r) of this section 
apply to the construction of any new major stationary source or the 
major modification of any existing major stationary source, except as 
this section otherwise provides.
    (iii) No new major stationary source or major modification to which 
the requirements of paragraphs (j) through (r)(5) of this section apply 
shall begin actual construction without a permit that states that the 
major stationary source or major modification will meet those 
requirements.
    (iv) Each plan shall use the specific provisions of paragraphs 
(a)(7)(iv)(a) through (f) of this section. Deviations from these 
provisions will be approved only if the State specifically demonstrates 
that the submitted provisions are more stringent than or at least as 
stringent in all respects as the corresponding provisions in paragraphs 
(a)(7)(iv)(a) through (f) of this section.
    (a) Except as otherwise provided in paragraphs (a)(7)(v) and (vi) of 
this section, and consistent with the definition of major modification 
contained in paragraph (b)(2) of this section, a project is a major 
modification for a regulated NSR pollutant if it causes two types of 
emissions increases--a significant emissions increase (as defined in 
paragraph (b)(39) of this section), and a significant net emissions 
increase (as defined in paragraphs (b)(3) and (b)(23) of this section). 
The project is not a major modification if it does not cause a 
significant emissions increase. If the project causes a significant 
emissions increase, then the project is a major modification only if it 
also results in a significant net emissions increase.
    (b) The procedure for calculating (before beginning actual 
construction) whether a significant emissions increase (i.e., the first 
step of the process) will occur depends upon the type of emissions units 
being modified, according to paragraphs (a)(7)(iv)(c) through (f) of 
this section. For these calculations, fugitive emissions (to the extent 
quantifiable) are included only if the emissions unit is part of one of 
the

[[Page 238]]

source categories listed in paragraph (b)(1)(iii) of this section or if 
the emission unit is located at a major stationary source that belongs 
to one of the listed source categories. Fugitive emissions are not 
included for those emissions units located at a facility whose primary 
activity is not represented by one of the source categories listed in 
paragraph (b)(1)(iii) of this section and that are not, by themselves, 
part of a listed source category. The procedure for calculating (before 
beginning actual construction) whether a significant net emissions 
increase will occur at the major stationary source (i.e., the second 
step of the process) is contained in the definition in paragraph (b)(3) 
of this section. Regardless of any such preconstruction projections, a 
major modification results if the project causes a significant emissions 
increase and a significant net emissions increase.
    (c) Actual-to-projected-actual applicability test for projects that 
only involve existing emissions units. A significant emissions increase 
of a regulated NSR pollutant is projected to occur if the sum of the 
difference between the projected actual emissions (as defined in 
paragraph (b)(40) of this section) and the baseline actual emissions (as 
defined in paragraphs (b)(47)(i) and (ii) of this section) for each 
existing emissions unit, equals or exceeds the significant amount for 
that pollutant (as defined in paragraph (b)(23) of this section).
    (d) Actual-to-potential test for projects that only involve 
construction of a new emissions unit(s). A significant emissions 
increase of a regulated NSR pollutant is projected to occur if the sum 
of the difference between the potential to emit (as defined in paragraph 
(b)(4) of this section) from each new emissions unit following 
completion of the project and the baseline actual emissions (as defined 
in paragraph (b)(47)(iii) of this section) of these units before the 
project equals or exceeds the significant amount for that pollutant (as 
defined in paragraph (b)(23) of this section).
    (e) [Reserved]
    (f) Hybrid test for projects that involve multiple types of 
emissions units. A significant emissions increase of a regulated NSR 
pollutant is projected to occur if the sum of the emissions increases 
for each emissions unit, using the method specified in paragraphs 
(a)(7)(iv)(c) through (d) of this section as applicable with respect to 
each emissions unit, for each type of emissions unit equals or exceeds 
the significant amount for that pollutant (as defined in paragraph 
(b)(23) of this section).
    (v) The plan shall require that for any major stationary source for 
a PAL for a regulated NSR pollutant, the major stationary source shall 
comply with requirements under paragraph (w) of this section.
    (b) Definitions. All State plans shall use the following definitions 
for the purposes of this section. Deviations from the following wording 
will be approved only if the State specifically demonstrates that the 
submitted definition is more stringent, or at least as stringent, in all 
respects as the corresponding definitions below:
    (1)(i) Major stationary source means:
    (a) Any of the following stationary sources of air pollutants which 
emits, or has the potential to emit, 100 tons per year or more of any 
regulated NSR pollutant: Fossil fuel-fired steam electric plants of more 
than 250 million British thermal units per hour heat input, coal 
cleaning plants (with thermal dryers), kraft pulp mills, portland cement 
plants, primary zinc smelters, iron and steel mill plants, primary 
aluminum ore reduction plants (with thermal dryers), primary copper 
smelters, municipal incinerators capable of charging more than 250 tons 
of refuse per day, hydrofluoric, sulfuric, and nitric acid plants, 
petroleum refineries, lime plants, phosphate rock processing plants, 
coke oven batteries, sulfur recovery plants, carbon black plants 
(furnace process), primary lead smelters, fuel conversion plants, 
sintering plants, secondary metal production plants, chemical process 
plants (which does not include ethanol production facilities that 
produce ethanol by natural fermentation included in NAICS codes 325193 
or 312140), fossil-fuel boilers (or combinations thereof) totaling more 
than 250 million British thermal units per hour heat input, petroleum 
storage and transfer units with a total

[[Page 239]]

storage capacity exceeding 300,000 barrels, taconite ore processing 
plants, glass fiber processing plants, and charcoal production plants;
    (b) Notwithstanding the stationary source size specified in 
paragraph (b)(1)(i)(a) of this section, any stationary source which 
emits, or has the potential to emit, 250 tons per year or more of a 
regulated NSR pollutant; or
    (c) Any physical change that would occur at a stationary source not 
otherwise qualifying under paragraph (b)(1) of this section, as a major 
stationary source if the change would constitute a major stationary 
source by itself.
    (ii) A major source that is major for volatile organic compounds or 
NOX shall be considered major for ozone.
    (iii) The fugitive emissions of a stationary source shall not be 
included in determining for any of the purposes of this section whether 
it is a major stationary source, unless the source belongs to one of the 
following categories of stationary sources:
    (a) Coal cleaning plants (with thermal dryers);
    (b) Kraft pulp mills;
    (c) Portland cement plants;
    (d) Primary zinc smelters;
    (e) Iron and steel mills;
    (f) Primary aluminum ore reduction plants;
    (g) Primary copper smelters;
    (h) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (i) Hydrofluoric, sulfuric, or nitric acid plants;
    (j) Petroleum refineries;
    (k) Lime plants;
    (l) Phosphate rock processing plants;
    (m) Coke oven batteries;
    (n) Sulfur recovery plants;
    (o) Carbon black plants (furnace process);
    (p) Primary lead smelters;
    (q) Fuel conversion plants;
    (r) Sintering plants;
    (s) Secondary metal production plants;
    (t) Chemical process plants--The term chemical processing plant 
shall not include ethanol production facilities that produce ethanol by 
natural fermentation included in NAICS codes 325193 or 312140;
    (u) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (v) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (w) Taconite ore processing plants;
    (x) Glass fiber processing plants;
    (y) Charcoal production plants;
    (z) Fossil fuel-fired steam electric plants of more that 250 million 
British thermal units per hour heat input;
    (aa) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.
    (2)(i) Major modification means any physical change in or change in 
the method of operation of a major stationary source that would result 
in: a significant emissions increase (as defined in paragraph (b)(39) of 
this section) of a regulated NSR pollutant (as defined in paragraph 
(b)(49) of this section); and a significant net emissions increase of 
that pollutant from the major stationary source.
    (ii) Any significant emissions increase (as defined at paragraph 
(b)(39) of this section) from any emissions units or net emissions 
increase (as defined in paragraph (b)(3) of this section) at a major 
stationary source that is significant for volatile organic compounds or 
NOX shall be considered significant for ozone.
    (iii) A physical change or change in the method of operation shall 
not include:
    (a) Routine maintenance, repair and replacement. Routine 
maintenance, repair and replacement shall include, but not be limited 
to, any activity(s) that meets the requirements of the equipment 
replacement provisions contained in paragraph (y) of this section;

    Note to paragraph (b)(2)(iii)(a): On December 24, 2003, the second 
sentence of this paragraph (b)(2)(iii)(a) is stayed indefinitely by 
court order. The stayed provisions will become effective immediately if 
the court terminates the stay. At that time, EPA will publish a document 
in the Federal Register advising the public of the termination of the 
stay.

    (b) Use of an alternative fuel or raw material by reason of any 
order under

[[Page 240]]

section 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) or by reason 
of a natural gas curtailment plan pursuant to the Federal Power Act;
    (c) Use of an alternative fuel by reason of an order or rule under 
section 125 of the Act;
    (d) Use of an alternative fuel at a steam generating unit to the 
extent that the fuel is generated from municipal solid waste;
    (e) Use of an alternative fuel or raw material by a stationary 
source which:
    (1) The source was capable of accommodating before January 6, 1975, 
unless such change would be prohibited under any federally enforceable 
permit condition which was established after January 6, 1975 pursuant to 
40 CFR 52.21 or under regulations approved pursuant to 40 CFR subpart I 
or Sec. 51.166; or
    (2) The source is approved to use under any permit issued under 40 
CFR 52.21 or under regulations approved pursuant to 40 CFR 51.166;
    (f) An increase in the hours of operation or in the production rate, 
unless such change would be prohibited under any federally enforceable 
permit condition which was established after January 6, 1975, pursuant 
to 40 CFR 52.21 or under regulations approved pursuant to 40 CFR subpart 
I or Sec. 51.166.
    (g) Any change in ownership at a stationary source.
    (h) [Reserved]
    (i) The installation, operation, cessation, or removal of a 
temporary clean coal technology demonstration project, provided that the 
project complies with:
    (1) The State implementation plan for the State in which the project 
is located; and
    (2) Other requirements necessary to attain and maintain the national 
ambient air quality standards during the project and after it is 
terminated.
    (j) The installation or operation of a permanent clean coal 
technology demonstration project that constitutes repowering, provided 
that the project does not result in an increase in the potential to emit 
of any regulated pollutant emitted by the unit. This exemption shall 
apply on a pollutant-by-pollutant basis.
    (k) The reactivation of a very clean coal-fired electric utility 
steam generating unit.
    (iv) This definition shall not apply with respect to a particular 
regulated NSR pollutant when the major stationary source is complying 
with the requirements under paragraph (w) of this section for a PAL for 
that pollutant. Instead, the definition at paragraph (w)(2)(viii) of 
this section shall apply.
    (v) Fugitive emissions shall not be included in determining for any 
of the purposes of this section whether a physical change in or change 
in the method of operation of a major stationary source is a major 
modification, unless the source belongs to one of the source categories 
listed in paragraph (b)(1)(iii) of this section.
    (3)(i) Net emissions increase means, with respect to any regulated 
NSR pollutant emitted by a major stationary source, the amount by which 
the sum of the following exceeds zero:
    (a) The increase in emissions from a particular physical change or 
change in the method of operation at a stationary source as calculated 
pursuant to paragraph (a)(7)(iv) of this section; and
    (b) Any other increases and decreases in actual emissions at the 
major stationary source that are contemporaneous with the particular 
change and are otherwise creditable. Baseline actual emissions for 
calculating increases and decreases under this paragraph (b)(3)(i)(b) 
shall be determined as provided in paragraph (b)(47), except that 
paragraphs (b)(47)(i)(c) and (b)(47)(ii)(d) of this section shall not 
apply.
    (ii) An increase or decrease in actual emissions is contemporaneous 
with the increase from the particular change only if it occurs within a 
reasonable period (to be specified by the State) before the date that 
the increase from the particular change occurs.
    (iii) An increase or decrease in actual emissions is creditable only 
if:
    (a) It occurs within a reasonable period (to be specified by the 
reviewing authority); and
    (b) The reviewing authority has not relied on it in issuing a permit 
for the

[[Page 241]]

source under regulations approved pursuant to this section, which permit 
is in effect when the increase in actual emissions from the particular 
change occurs; and
    (c) The increase or decrease in emissions did not occur at a Clean 
Unit, except as provided in paragraphs (t)(8) and (u)(10) of this 
section; and
    (d) As it pertains to an increase or decrease in fugitive emissions 
(to the extent quantifiable), it occurs at an emissions unit that is 
part of one of the source categories listed in paragraph (b)(1)(iii) of 
this section or it occurs at an emission unit that is located at a major 
stationary source that belongs to one of the listed source categories. 
Fugitive emission increases or decreases are not included for those 
emissions units located at a facility whose primary activity is not 
represented by one of the source categories listed in paragraph 
(b)(1)(iii) of this section and that are not, by themselves, part of a 
listed source category.
    (iv) An increase or decrease in actual emissions of sulfur dioxide, 
particulate matter, or nitrogen oxides that occurs before the applicable 
minor source baseline date is creditable only if it is required to be 
considered in calculating the amount of maximum allowable increases 
remaining available.
    (v) An increase in actual emissions is creditable only to the extent 
that the new level of actual emissions exceeds the old level.
    (vi) A decrease in actual emissions is creditable only to the extent 
that:
    (a) The old level of actual emissions or the old level of allowable 
emissions, whichever is lower, exceeds the new level of actual 
emissions;
    (b) It is enforceable as a practical matter at and after the time 
that actual construction on the particular change begins;
    (c) It has approximately the same qualitative significance for 
public health and welfare as that attributed to the increase from the 
particular change; and
    (vii) An increase that results from a physical change at a source 
occurs when the emissions unit on which construction occurred becomes 
operational and begins to emit a particular pollutant. Any replacement 
unit that requires shakedown becomes operational only after a reasonable 
shakedown period, not to exceed 180 days.
    (viii) Paragraph (b)(21)(ii) of this section shall not apply for 
determining creditable increases and decreases.
    (4) Potential to emit means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant, including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
if the limitation or the effect it would have on emissions is federally 
enforceable. Secondary emissions do not count in determining the 
potential to emit of a stationary source.
    (5) Stationary source means any building, structure, facility, or 
installation which emits or may emit a regulated NSR pollutant.
    (6) Building, structure, facility, or installation means all of the 
pollutant-emitting activities which belong to the same industrial 
grouping, are located on one or more contiguous or adjacent properties, 
and are under the control of the same person (or persons under common 
control) except the activities of any vessel. Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same Major Group (i.e., which have the same two-
digit code) as described in the Standard Industrial Classification 
Manual, 1972, as amended by the 1977 Supplement (U.S. Government 
Printing Office stock numbers 4101-0066 and 003-005-00176-0, 
respectively).
    (7) Emissions unit means any part of a stationary source that emits 
or would have the potential to emit any regulated NSR pollutant and 
includes an electric utility steam generating unit as defined in 
paragraph (b)(30) of this section. For purposes of this section, there 
are two types of emissions units as described in paragraphs (b)(7)(i) 
and (ii) of this section.
    (i) A new emissions unit is any emissions unit that is (or will be) 
newly constructed and that has existed for less than 2 years from the 
date such emissions unit first operated.

[[Page 242]]

    (ii) An existing emissions unit is any emissions unit that does not 
meet the requirements in paragraph (b)(7)(i) of this section. A 
replacement unit, as defined in paragraph (b)(32) of this section, is an 
existing emissions unit.
    (8) Construction means any physical change or change in the method 
of operation (including fabrication, erection, installation, demolition, 
or modification of an emissions unit) that would result in a change in 
emissions.
    (9) Commence as applied to construction of a major stationary source 
or major modification means that the owner or operator has all necessary 
preconstruction approvals or permits and either has:
    (i) Begun, or caused to begin, a continuous program of actual on-
site construction of the source, to be completed within a reasonable 
time; or
    (ii) Entered into binding agreements or contractual obligations, 
which cannot be cancelled or modified without substantial loss to the 
owner or operator, to undertake a program of actual construction of the 
source to be completed within a reasonable time.
    (10) Necessary preconstruction approvals or permits means those 
permits or approvals required under Federal air quality control laws and 
regulations and those air quality control laws and regulations which are 
part of the applicable State Implementation Plan.
    (11) Begin actual construction means, in general, initiation of 
physical on-site construction activities on an emissions unit which are 
of a permanent nature. Such activities include, but are not limited to, 
installation of building supports and foundations, laying of underground 
pipework, and construction of permanent storage structures. With respect 
to a change in method of operation this term refers to those on-site 
activities, other than preparatory activities, which mark the initiation 
of the change.
    (12) Best available control technology means an emissions limitation 
(including a visible emissions standard) based on the maximum degree of 
reduction for each a regulated NSR pollutant which would be emitted from 
any proposed major stationary source or major modification which the 
reviewing authority, on a case-by-case basis, taking into account 
energy, environmental, and economic impacts and other costs, determines 
is achievable for such source or modification through application of 
production processes or available methods, systems, and techniques, 
including fuel cleaning or treatment or innovative fuel combination 
techniques for control of such pollutant. In no event shall application 
of best available control technology result in emissions of any 
pollutant which would exceed the emissions allowed by any applicable 
standard under 40 CFR parts 60 and 61. If the reviewing authority 
determines that technological or economic limitations on the application 
of measurement methodology to a particular emissions unit would make the 
imposition of an emissions standard infeasible, a design, equipment, 
work practice, operational standard or combination thereof, may be 
prescribed instead to satisfy the requirement for the application of 
best available control technology. Such standard shall, to the degree 
possible, set forth the emissions reduction achievable by implementation 
of such design, equipment, work practice or operation, and shall provide 
for compliance by means which achieve equivalent results.
    (13)(i) Baseline concentration means that ambient concentration 
level that exists in the baseline area at the time of the applicable 
minor source baseline date. A baseline concentration is determined for 
each pollutant for which a minor source baseline date is established and 
shall include:
    (a) The actual emissions, as defined in paragraph (b)(21) of this 
section, representative of sources in existence on the applicable minor 
source baseline date, except as provided in paragraph (b)(13)(ii) of 
this section;
    (b) The allowable emissions of major stationary sources that 
commenced construction before the major source baseline date, but were 
not in operation by the applicable minor source baseline date.
    (ii) The following will not be included in the baseline 
concentration and will affect the applicable maximum allowable 
increase(s):
    (a) Actual emissions, as defined in paragraph (b)(21) of this 
section, from any major stationary source on which

[[Page 243]]

construction commenced after the major source baseline date; and
    (b) Actual emissions increases and decreases, as defined in 
paragraph (b)(21) of this section, at any stationary source occurring 
after the minor source baseline date.
    (14)(i) Major source baseline date means:
    (a) In the case of particulate matter and sulfur dioxide, January 6, 
1975, and
    (b) In the case of nitrogen dioxide, February 8, 1988.
    (ii) Minor source baseline date means the earliest date after the 
trigger date on which a major stationary source or a major modification 
subject to 40 CFR 52.21 or to regulations approved pursuant to 40 CFR 
51.166 submits a complete application under the relevant regulations. 
The trigger date is:
    (a) In the case of particulate matter and sulfur dioxide, August 7, 
1977, and
    (b) In the case of nitrogen dioxide, February 8, 1988.
    (iii) The baseline date is established for each pollutant for which 
increments or other equivalent measures have been established if:
    (a) The area in which the proposed source or modification would 
construct is designated as attainment or unclassifiable under section 
107(d)(i) (D) or (E) of the Act for the pollutant on the date of its 
complete application under 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR 51.166; and
    (b) In the case of a major stationary source, the pollutant would be 
emitted in significant amounts, or, in the case of a major modification, 
there would be a significant net emissions increase of the pollutant.
    (iv) Any minor source baseline date established originally for the 
TSP increments shall remain in effect and shall apply for purposes of 
determining the amount of available PM-10 increments, except that the 
reviewing authority may rescind any such minor source baseline date 
where it can be shown, to the satisfaction of the reviewing authority, 
that the emissions increase from the major stationary source, or the net 
emissions increase from the major modification, responsible for 
triggering that date did not result in a significant amount of PM-10 
emissions.
    (15)(i) Baseline area means any intrastate area (and every part 
thereof) designated as attainment or unclassifiable under section 
107(d)(1) (D) or (E) of the Act in which the major source or major 
modification establishing the minor source baseline date would construct 
or would have an air quality impact equal to or greater than 1 [micro]g/
m\3\ (annual average) of the pollutant for which the minor source 
baseline date is established.
    (ii) Area redesignations under section 107(d)(1) (D) or (E) of the 
Act cannot intersect or be smaller than the area of impact of any major 
stationary source or major modification which:
    (a) Establishes a minor source baseline date; or
    (b) Is subject to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR 51.166, and would be constructed in the same State as 
the State proposing the redesignation.
    (iii) Any baseline area established originally for the TSP 
increments shall remain in effect and shall apply for purposes of 
determining the amount of available PM-10 increments, except that such 
baseline area shall not remain in effect if the permit authority 
rescinds the corresponding minor source baseline date in accordance with 
paragraph (b)(14)(iv) of this section.
    (16) Allowable emissions means the emissions rate of a stationary 
source calculated using the maximum rated capacity of the source (unless 
the source is subject to federally enforceable limits which restrict the 
operating rate, or hours of operation, or both) and the most stringent 
of the following:
    (i) The applicable standards as set forth in 40 CFR parts 60 and 61;
    (ii) The applicable State Implementation Plan emissions limitation, 
including those with a future compliance date; or
    (iii) The emissions rate specified as a federally enforceable permit 
condition.
    (17) Federally enforceable means all limitations and conditions 
which are enforceable by the Administrator, including those requirements 
developed pursuant to 40 CFR parts 60 and 61, requirements within any 
applicable State implementation plan, any permit requirements 
established pursuant to 40

[[Page 244]]

CFR 52.21 or under regulations approved pursuant to 40 CFR part 51, 
subpart I, including operating permits issued under an EPA-approved 
program that is incorporated into the State implementation plan and 
expressly requires adherence to any permit issued under such program.
    (18) Secondary emissions means emissions which occur as a result of 
the construction or operation of a major stationary source or major 
modification, but do not come from the major stationary source or major 
modification itself. For the purposes of this section, secondary 
emissions must be specific, well defined, quantifiable, and impact the 
same general areas the stationary source modification which causes the 
secondary emissions. Secondary emissions include emissions from any 
offsite support facility which would not be constructed or increase its 
emissions except as a result of the construction or operation of the 
major stationary source or major modification. Secondary emissions do 
not include any emissions which come directly from a mobile source, such 
as emissions from the tailpipe of a motor vehicle, from a train, or from 
a vessel.
    (19) Innovative control technology means any system of air pollution 
control that has not been adequately demonstrated in practice, but would 
have a substantial likelihood of achieving greater continuous emissions 
reduction than any control system in current practice or of achieving at 
least comparable reductions at lower cost in terms of energy, economics, 
or nonair quality environmental impacts.
    (20) Fugitive emissions means those emissions which could not 
reasonably pass through a stack, chimney, vent, or other functionally 
equivalent opening. Fugitive emissions, to the extent quantifiable, are 
addressed as follows for the purposes of this section:
    (i) In calculating whether a project will cause a significant 
emissions increase, fugitive emissions are included only for those 
emissions units that are part of one of the source categories listed in 
paragraph (b)(1)(iii) of this section, or for any emissions units that 
are located at a major stationary source that belongs to one of the 
listed source categories. Fugitive emissions are not included for those 
emissions units located at a facility whose primary activity is not 
represented by one of the source categories listed in paragraph 
(b)(1)(iii) of this section and that are not, by themselves, part of a 
listed source category. (See paragraph (a)(7)(iv)(b) of this section.)
    (ii) In determining whether a stationary source or modification is 
major, fugitive emissions from an emissions unit are included only if 
the emissions unit is part of one of the stationary source categories 
listed in paragraph (b)(1)(iii) of this section or the emissions unit is 
located at a stationary source that belongs to one of the source 
categories listed in paragraph (b)(1)(iii) of this section. Fugitive 
emissions are not included for those emissions units located at a 
facility whose primary activity is not represented by one of the source 
categories listed in paragraph (b)(1)(iii) of this section and that are 
not, by themselves, part of a listed source category. (See paragraphs 
(b)(1)(iii) and (b)(2)(v) of this section.)
    (iii) For purposes of determining the net emissions increase 
associated with a project, an increase or decrease in fugitive emissions 
is creditable only if it occurs at an emissions unit that is part of one 
of the source categories listed in paragraph (b)(1)(iii) of this section 
or if the emissions unit is located at a major stationary source that 
belongs to one of the listed source categories. Fugitive emission 
increases or decreases are not included for those emissions units 
located at a facility whose primary activity is not represented by one 
of the source categories listed in paragraph (b)(1)(iii) of this section 
and that are not, by themselves, part of a listed source category. (See 
paragraph (b)(3)(iii)(d) of this section.)
    (iv) For purposes of determining the projected actual emissions of 
an emissions unit after a project, fugitive emissions are included only 
if the emissions unit is part of one of the source categories listed in 
paragraph (b)(1)(iii) of this section or if the emissions unit is 
located at a major stationary source that belongs to one of the listed 
source categories. Fugitive emissions are not included for those 
emissions units located at a facility

[[Page 245]]

whose primary activity is not represented by one of the source 
categories listed in paragraph (b)(1)(iii) of this section and that are 
not, by themselves, part of a listed source category. (See paragraph 
(b)(40)(ii)(b) and (d) of this section.
    (v) For purposes of determining the baseline actual emissions of an 
emissions unit, fugitive emissions are included only if the emissions 
unit is part of one of the source categories listed in paragraph 
(b)(1)(iii) of this section or if the emissions unit is located at a 
major stationary source that belongs to one of the listed source 
categories, except that, for a PAL, fugitive emissions shall be included 
regardless of the source category. With the exception of PALs, fugitive 
emissions are not included for those emissions units located at a 
facility whose primary activity is not represented by one of the source 
categories listed in paragraph (b)(1)(iii) of this section and that are 
not, by themselves, part of a listed source category. (See paragraphs 
(b)(47)(i)(a), (b)(47)(ii)(a), (b)(47)(iii), and (b)(47)(iv) of this 
section.)
    (vi) For purposes of monitoring and reporting emissions from a 
project after normal operations have been resumed, fugitive emissions 
are included only for those emissions units that are part of one of the 
source categories listed in paragraph (b)(1)(iii) of this section, or 
for any emissions units that are located at a major stationary source 
that belongs to one of the listed source categories. Fugitive emissions 
are not included for those emissions units located at a facility whose 
primary activity is not represented by one of the source categories 
listed in paragraph (b)(1)(iii) of this section and that are not, by 
themselves, part of a listed source category. (See paragraphs 
(r)(6)(iii) and (iv) of this section.)
    (vii) For all other purposes of this section, fugitive emissions are 
treated in the same manner as other, non-fugitive emissions. This 
includes, but is not limited to, the treatment of fugitive emissions for 
the application of best available control technology (see paragraph (j) 
of this section), source impact analysis (see paragraph (k) of this 
section), additional impact analyses (see paragraph (o) of this 
section), and PALs (see paragraph (w)(4)(i)(d) of this section).
    (21)(i) Actual emissions means the actual rate of emissions of a 
regulated NSR pollutant from an emissions unit, as determined in 
accordance with paragraphs (b)(21)(ii) through (iv) of this section, 
except that this definition shall not apply for calculating whether a 
significant emissions increase has occurred, or for establishing a PAL 
under paragraph (w) of this section. Instead, paragraphs (b)(40) and 
(b)(47) of this section shall apply for those purposes.
    (ii) In general, actual emissions as of a particular date shall 
equal the average rate, in tons per year, at which the unit actually 
emitted the pollutant during a consecutive 24-month period which 
precedes the particular date and which is representative of normal 
source operation. The reviewing authority shall allow the use of a 
different time period upon a determination that it is more 
representative of normal source operation. Actual emissions shall be 
calculated using the unit's actual operating hours, production rates, 
and types of materials processed, stored, or combusted during the 
selected time period.
    (iii) The reviewing authority may presume that source-specific 
allowable emissions for the unit are equivalent to the actual emissions 
of the unit.
    (iv) For any emissions unit that has not begun normal operations on 
the particular date, actual emissions shall equal the potential to emit 
of the unit on that date.
    (22) Complete means, in reference to an application for a permit, 
that the application contains all the information necessary for 
processing the application. Designating an application complete for 
purposes of permit processing does not preclude the reviewing authority 
from requesting or accepting any additional information.
    (23)(i) Significant means, in reference to a net emissions increase 
or the potential of a source to emit any of the following pollutants, a 
rate of emissions that would equal or exceed any of the following rates:

                      Pollutant and Emissions Rate

Carbon monoxide: 100 tons per year (tpy)
Nitrogen oxides: 40 tpy
Sulfur dioxide: 40 tpy

[[Page 246]]

Particulate matter: 25 tpy of particulate matter emissions. 15 tpy of 
PM10 emissions
PM2.5: 10 tpy of direct PM2.5 emissions; 40 tpy of 
sulfur dioxide emissions; 40 tpy of nitrogen oxide emissions unless 
demonstrated not to be a PM2.5 precursor under paragraph 
(b)(49) of this section
Ozone: 40 tpy of volatile organic compounds or nitrogen oxides
Lead: 0.6 tpy
Fluorides: 3 tpy
Sulfuric acid mist: 7 tpy
Hydrogen sulfide (H2S): 10 tpy
Total reduced sulfur (including H2S): 10 tpy
Reduced sulfur compounds (including H2S): 10 tpy
Municipal waste combustor organics (measured as total tetra-through 
octa-chlorinated dibenzo-p-dioxins and dibenzofurans): 3.2 x 10-
-6 megagrams per year (3.5 x 10-6 tons per year)
Municipal waste combustor metals (measured as particulate matter): 14 
megagrams per year (15 tons per year)
Municipal waste combustor acid gases (measured as sulfur dioxide and 
hydrogen chloride): 36 megagrams per year (40 tons per year)
Municipal solid waste landfill emissions (measured as nonmethane organic 
compounds): 45 megagrams per year (50 tons per year)

    (ii) Significant means, in reference to a net emissions increase or 
the potential of a source to emit a regulated NSR pollutant that 
paragraph (b)(23)(i) of this section, does not list, any emissions rate.
    (iii) Notwithstanding paragraph (b)(23)(i) of this section, 
significant means any emissions rate or any net emissions increase 
associated with a major stationary source or major modification, which 
would construct within 10 kilometers of a Class I area, and have an 
impact on such area equal to or greater than 1 [micro]g/m\3\ (24-hour 
average).
    (24) Federal Land Manager means, with respect to any lands in the 
United States, the Secretary of the department with authority over such 
lands.
    (25) High terrain means any area having an elevation 900 feet or 
more above the base of the stack of a source.
    (26) Low terrain means any area other than high terrain.
    (27) Indian Reservation means any federally recognized reservation 
established by Treaty, Agreement, Executive Order, or Act of Congress.
    (28) Indian Governing Body means the governing body of any tribe, 
band, or group of Indians subject to the jurisdiction of the United 
States and recognized by the United States as possessing power of self-
government.
    (29) Volatile organic compounds (VOC) is as defined in Sec. 
51.100(s) of this part.
    (30) Electric utility steam generating unit means any steam electric 
generating unit that is constructed for the purpose of supplying more 
than one-third of its potential electric output capacity and more than 
25 MW electrical output to any utility power distribution system for 
sale. Any steam supplied to a steam distribution system for the purpose 
of providing steam to a steam-electric generator that would produce 
electrical energy for sale is also considered in determining the 
electrical energy output capacity of the affected facility.
    (31) [Reserved]
    (32) Replacement unit means an emissions unit for which all the 
criteria listed in paragraphs (b)(32)(i) through (iv) of this section 
are met. No creditable emission reductions shall be generated from 
shutting down the existing emissions unit that is replaced.
    (i) The emissions unit is a reconstructed unit within the meaning of 
Sec. 60.15(b)(1) of this chapter, or the emissions unit completely 
takes the place of an existing emissions unit.
    (ii) The emissions unit is identical to or functionally equivalent 
to the replaced emissions unit.
    (iii) The replacement does not change the basic design parameter(s) 
(as discussed in paragraph (y)(2) of this section) of the process unit.
    (iv) The replaced emissions unit is permanently removed from the 
major stationary source, otherwise permanently disabled, or permanently 
barred from operation by a permit that is enforceable as a practical 
matter. If the replaced emissions unit is brought back into operation, 
it shall constitute a new emissions unit.
    (33) Clean coal technology means any technology, including 
technologies applied at the precombustion, combustion, or post 
combustion stage, at a new or existing facility which will achieve 
significant reductions in air emissions of sulfur dioxide or oxides of

[[Page 247]]

nitrogen associated with the utilization of coal in the generation of 
electricity, or process steam which was not in widespread use as of 
November 15, 1990.
    (34) Clean coal technology demonstration project means a project 
using funds appropriated under the heading ``Department of Energy--Clean 
Coal Technology'', up to a total amount of $2,500,000,000 for commercial 
demonstration of clean coal technology, or similar projects funded 
through appropriations for the Environmental Protection Agency. The 
Federal contribution for a qualifying project shall be at least 20 
percent of the total cost of the demonstration project.
    (35) Temporary clean coal technology demonstration project means a 
clean coal technology demonstration project that is operated for a 
period of 5 years or less, and which complies with the State 
implementation plan for the State in which the project is located and 
other requirements necessary to attain and maintain the national ambient 
air quality standards during and after the project is terminated.
    (36)(i) Repowering means replacement of an existing coal-fired 
boiler with one of the following clean coal technologies: atmospheric or 
pressurized fluidized bed combustion, integrated gasification combined 
cycle, magnetohydrodynamics, direct and indirect coal-fired turbines, 
integrated gasification fuel cells, or as determined by the 
Administrator, in consultation with the Secretary of Energy, a 
derivative of one or more of these technologies, and any other 
technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of November 15, 1990.
    (ii) Repowering shall also include any oil and/or gas-fired unit 
which has been awarded clean coal technology demonstration funding as of 
January 1, 1991, by the Department of Energy.
    (iii) The reviewing authority shall give expedited consideration to 
permit applications for any source that satisfies the requirements of 
this subsection and is granted an extension under section 409 of the 
Clean Air Act.
    (37) Reactivation of a very clean coal-fired electric utility steam 
generating unit means any physical change or change in the method of 
operation associated with the commencement of commercial operations by a 
coal-fired utility unit after a period of discontinued operation where 
the unit:
    (i) Has not been in operation for the two-year period prior to the 
enactment of the Clean Air Act Amendments of 1990, and the emissions 
from such unit continue to be carried in the permitting authority's 
emissions inventory at the time of enactment;
    (ii) Was equipped prior to shutdown with a continuous system of 
emissions control that achieves a removal efficiency for sulfur dioxide 
of no less than 85 percent and a removal efficiency for particulates of 
no less than 98 percent;
    (iii) Is equipped with low-NOX burners prior to the time 
of commencement of operations following reactivation; and
    (iv) Is otherwise in compliance with the requirements of the Clean 
Air Act.
    (38) Pollution prevention means any activity that through process 
changes, product reformulation or redesign, or substitution of less 
polluting raw materials, eliminates or reduces the release of air 
pollutants (including fugitive emissions) and other pollutants to the 
environment prior to recycling, treatment, or disposal; it does not mean 
recycling (other than certain ``in-process recycling'' practices), 
energy recovery, treatment, or disposal.
    (39) Significant emissions increase means, for a regulated NSR 
pollutant, an increase in emissions that is significant (as defined in 
paragraph (b)(23) of this section) for that pollutant.
    (40)(i) Projected actual emissions means the maximum annual rate, in 
tons per year, at which an existing emissions unit is projected to emit 
a regulated NSR pollutant in any one of the 5 years (12-month period) 
following the date the unit resumes regular operation after the project, 
or in any one of the 10 years following that date, if the project 
involves increasing the emissions unit's design capacity or its 
potential to emit that regulated NSR pollutant, and full utilization of 
the unit

[[Page 248]]

would result in a significant emissions increase, or a significant net 
emissions increase at the major stationary source.
    (ii) In determining the projected actual emissions under paragraph 
(b)(40)(i) of this section (before beginning actual construction), the 
owner or operator of the major stationary source:
    (a) Shall consider all relevant information, including but not 
limited to, historical operational data, the company's own 
representations, the company's expected business activity and the 
company's highest projections of business activity, the company's 
filings with the State or Federal regulatory authorities, and compliance 
plans under the approved plan; and
    (b) Shall include emissions associated with startups, shutdowns, and 
malfunctions; and, for an emissions unit that is part of one of the 
source categories listed in paragraph (b)(1)(iii) of this section or for 
an emissions unit that is located at a major stationary source that 
belongs to one of the listed source categories, shall include fugitive 
emissions (to the extent
    (c) Shall exclude, in calculating any increase in emissions that 
results from the particular project, that portion of the unit's 
emissions following the project that an existing unit could have 
accommodated during the consecutive 24-month period used to establish 
the baseline actual emissions under paragraph (b)(47) of this section 
and that are also unrelated to the particular project, including any 
increased utilization due to product demand growth; or,
    (d) In lieu of using the method set out in paragraphs (b)(40)(ii)(a) 
through (c) of this section, may elect to use the emissions unit's 
potential to emit, in tons per year, as defined under paragraph (b)(4) 
of this section. For this purpose, if the emissions unit is part of one 
of the source categories listed in paragraph (b)(1)(iii) of this section 
or if the emissions unit is located at a major stationary source that 
belongs to one of the listed source categories, the unit's potential to 
emit shall include fugitive emissions (to the extent quantifiable).
    (41) [Reserved]
    (42) Prevention of Significant Deterioration Program (PSD) program 
means a major source preconstruction permit program that has been 
approved by the Administrator and incorporated into the plan to 
implement the requirements of this section, or the program in Sec. 
52.21 of this chapter. Any permit issued under such a program is a major 
NSR permit.
    (43) Continuous emissions monitoring system (CEMS) means all of the 
equipment that may be required to meet the data acquisition and 
availability requirements of this section, to sample, condition (if 
applicable), analyze, and provide a record of emissions on a continuous 
basis.
    (44) Predictive emissions monitoring system (PEMS) means all of the 
equipment necessary to monitor process and control device operational 
parameters (for example, control device secondary voltages and electric 
currents) and other information (for example, gas flow rate, O\2\ or 
CO\2\ concentrations), and calculate and record the mass emissions rate 
(for example, lb/hr) on a continuous basis.
    (45) Continuous parameter monitoring system (CPMS) means all of the 
equipment necessary to meet the data acquisition and availability 
requirements of this section, to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O\2\ or CO\2\ concentrations), and to record average operational 
parameter value(s) on a continuous basis.
    (46) Continuous emissions rate monitoring system (CERMS) means the 
total equipment required for the determination and recording of the 
pollutant mass emissions rate (in terms of mass per unit of time).
    (47) Baseline actual emissions means the rate of emissions, in tons 
per year, of a regulated NSR pollutant, as determined in accordance with 
paragraphs (b)(47)(i) through (iv) of this section.
    (i) For any existing electric utility steam generating unit, 
baseline actual emissions means the average rate, in tons per year, at 
which the unit actually emitted the pollutant during any consecutive 24-
month period selected by the owner or operator within the 5-

[[Page 249]]

year period immediately preceding when the owner or operator begins 
actual construction of the project. The reviewing authority shall allow 
the use of a different time period upon a determination that it is more 
representative of normal source operation.
    (a) The average rate shall include emissions associated with 
startups, shutdowns, and malfunctions; and, for an emissions unit that 
is part of one of the source categories listed in paragraph (b)(1)(iii) 
of this section or for an emissions unit that is located at a major 
stationary source that belongs to one of the listed source categories, 
shall include fugitive emissions (to the extent quantifiable).
    (b) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (c) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used For each 
regulated NSR pollutant.
    (d) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraph (b)(47)(i)(b) of this section.
    (ii) For an existing emissions unit (other than an electric utility 
steam generating unit), baseline actual emissions means the average 
rate, in tons per year, at which the emissions unit actually emitted the 
pollutant during any consecutive 24-month period selected by the owner 
or operator within the 10-year period immediately preceding either the 
date the owner or operator begins actual construction of the project, or 
the date a complete permit application is received by the reviewing 
authority for a permit required either under this section or under a 
plan approved by the Administrator, whichever is earlier, except that 
the 10-year period shall not include any period earlier than November 
15, 1990.
    (a) The average rate shall include emissions associated with 
startups, shutdowns, and malfunctions; and, for an emissions unit that 
is part of one of the source categories listed in paragraph (b)(1)(iii) 
of this section or for an emissions unit that is located at a major 
stationary source that belongs to one of the listed source categories, 
shall include fugitive emissions (to the extent quantifiable).
    (b) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (c) The average rate shall be adjusted downward to exclude any 
emissions that would have exceeded an emission limitation with which the 
major stationary source must currently comply, had such major stationary 
source been required to comply with such limitations during the 
consecutive 24-month period. However, if an emission limitation is part 
of a maximum achievable control technology standard that the 
Administrator proposed or promulgated under part 63 of this chapter, the 
baseline actual emissions need only be adjusted if the State has taken 
credit for such emissions reductions in an attainment demonstration or 
maintenance plan consistent with the requirements of Sec. 
51.165(a)(3)(ii)(G).
    (d) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used For each 
regulated NSR pollutant.
    (e) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraphs (b)(47)(ii)(b) and (c) of this section.
    (iii) For a new emissions unit, the baseline actual emissions for 
purposes of determining the emissions increase

[[Page 250]]

that will result from the initial construction and operation of such 
unit shall equal zero; and thereafter, for all other purposes, shall 
equal the unit's potential to emit. In the latter case, fugitive 
emissions, to the extent quantifiable, shall be included only if the 
emissions unit is part of one of the source categories listed in 
paragraph (b)(1)(iii) of this section or if the emissions unit is 
located at a major stationary source that belongs to one of the listed 
source categories.
    (iv) For a PAL for a major stationary source, the baseline actual 
emissions shall be calculated for existing electric utility steam 
generating units in accordance with the procedures contained in 
paragraph (b)(47)(i) of this section, for other existing emissions units 
in accordance with the procedures contained in paragraph (b)(47)(ii) of 
this section, and for a new emissions unit in accordance with the 
procedures contained in paragraph (b)(47)(iii) of this section, except 
that fugitive emissions (to the extent quantifiable) shall be included 
regardless of the source category.
    (48) [Reserved]
    (49) Regulated NSR pollutant, for purposes of this section, means 
the following:
    (i) Any pollutant for which a national ambient air quality standard 
has been promulgated and any pollutant identified under this paragraph 
(b)(49)(i) as a constituent or precursor to such pollutant. Precursors 
identified by the Administrator for purposes of NSR are the following:
    (a) Volatile organic compounds and nitrogen oxides are precursors to 
ozone in all attainment and unclassifiable areas.
    (b) Sulfur dioxide is a precursor to PM2.5 in all 
attainment and unclassifiable areas.
    (c) Nitrogen oxides are presumed to be precursors to 
PM2.5 in all attainment and unclassifiable areas, unless the 
State demonstrates to the Administrator's satisfaction or EPA 
demonstrates that emissions of nitrogen oxides from sources in a 
specific area are not a significant contributor to that area's ambient 
PM2.5 concentrations.
    (d) Volatile organic compounds are presumed not to be precursors to 
PM2.5 in any attainment or unclassifiable area, unless the 
State demonstrates to the Administrator's satisfaction or EPA 
demonstrates that emissions of volatile organic compounds from sources 
in a specific area are a significant contributor to that area's ambient 
PM2.5 concentrations.
    (ii) Any pollutant that is subject to any standard promulgated under 
section 111 of the Act;
    (iii) Any Class I or II substance subject to a standard promulgated 
under or established by title VI of the Act;
    (iv) Any pollutant that otherwise is subject to regulation under the 
Act; except that any or all hazardous air pollutants either listed in 
section 112 of the Act or added to the list pursuant to section 
112(b)(2) of the Act, which have not been delisted pursuant to section 
112(b)(3) of the Act, are not regulated NSR pollutants unless the listed 
hazardous air pollutant is also regulated as a constituent or precursor 
of a general pollutant listed under section 108 of the Act.
    (v))-(vi) [Reserved]
    (50) Reviewing authority means the State air pollution control 
agency, local agency, other State agency, Indian tribe, or other agency 
authorized by the Administrator to carry out a permit program under 
Sec. 51.165 and this section, or the Administrator in the case of EPA-
implemented permit programs under Sec. 52.21 of this chapter.
    (51) Project means a physical change in, or change in method of 
operation of, an existing major stationary source.
    (52) Lowest achievable emission rate (LAER) is as defined in Sec. 
51.165(a)(1)(xiii).
    (53)(i) In general, process unit means any collection of structures 
and/or equipment that processes, assembles, applies, blends, or 
otherwise uses material inputs to produce or store an intermediate or a 
completed product. A single stationary source may contain more than one 
process unit, and a process unit may contain more than one emissions 
unit.
    (ii) Pollution control equipment is not part of the process unit, 
unless it serves a dual function as both process and control equipment. 
Administrative

[[Page 251]]

and warehousing facilities are not part of the process unit.
    (iii) For replacement cost purposes, components shared between two 
or more process units are proportionately allocated based on capacity.
    (iv) The following list identifies the process units at specific 
categories of stationary sources.
    (a) For a steam electric generating facility, the process unit 
consists of those portions of the plant that contribute directly to the 
production of electricity. For example, at a pulverized coal-fired 
facility, the process unit would generally be the combination of those 
systems from the coal receiving equipment through the emission stack 
(excluding post-combustion pollution controls), including the coal 
handling equipment, pulverizers or coal crushers, feedwater heaters, ash 
handling, boiler, burners, turbine-generator set, condenser, cooling 
tower, water treatment system, air preheaters, and operating control 
systems. Each separate generating unit is a separate process unit.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and/or distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as steam generators and hydrogen production 
units; and those that load, unload, blend or store intermediate or 
completed products.
    (c) For an incinerator, the process unit would consist of components 
from the feed pit or refuse pit to the stack, including conveyors, 
combustion devices, heat exchangers and steam generators, quench tanks, 
and fans.

    Note to paragraph (b)(53): By a court order on December 24, 2003, 
this paragraph (b)(53) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.

    (54) Functionally equivalent component means a component that serves 
the same purpose as the replaced component.

    Note to paragraph (b)(54): By a court order on December 24, 2003, 
this paragraph (b)(54) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.

    (55) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (b)(56) of this section.

    Note to paragraph (b)(55): By a court order on December 24, 2003, 
this paragraph (b)(55) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.

    (56) Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased equipment 
costs); the costs of labor and materials for installing that equipment 
(direct installation costs); the costs of site preparation and 
buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.

    Note to paragraph (b)(56): By a court order on December 24, 2003, 
this paragraph (b)(56) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.

    (c) Ambient air increments and other measures. (1) The plan shall 
contain emission limitations and such other measures as may be necessary 
to assure that in areas designated as Class I, II, or III, increases in 
pollutant concentrations over the baseline concentration shall be 
limited to the following:

[[Page 252]]



------------------------------------------------------------------------
                                                              Maximum
                                                             allowable
                                                             increase
                        Pollutant                           (micrograms
                                                             per cubic
                                                              meter)
------------------------------------------------------------------------
                                 Class I
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................               4
    PM10, 24-hr maximum.................................               8
Sulfur dioxide:
    Annual arithmetic mean..............................               2
    24-hr maximum.......................................               5
    3-hr maximum........................................              25
Nitrogen dioxide:
    Annual arithmetic mean..............................             2.5
------------------------------------------------------------------------
                                Class II
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................              17
    PM10, 24-hr maximum.................................              30
Sulfur dioxide:
    Annual arithmetic mean..............................              20
    24-hr maximum.......................................              91
    3-hr maximum........................................             512
Nitrogen dioxide:
    Annual arithmetic mean..............................              25
------------------------------------------------------------------------
                                Class III
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................              34
    PM10, 24-hr maximum.................................              60
Sulfur dioxide:
    Annual arithmetic mean..............................              40
    24-hr maximum.......................................             182
    3-hr maximum........................................             700
Nitrogen dioxide:
    Annual arithmetic mean..............................              50
------------------------------------------------------------------------

    For any period other than an annual period, the applicable maximum 
allowable increase may be exceeded during one such period per year at 
any one location.
    (2) Where the State can demonstrate that it has alternative measures 
in its plan other than maximum allowable increases that satisfy the 
requirements in sections 166(c) and 166(d) of the Clean Air Act for 
nitrogen oxides, the requirements for maximum allowable increases for 
nitrogen dioxide under paragraph (c)(1) of this section shall not apply 
upon approval of the plan by the Administrator.
    (d) Ambient air ceilings. The plan shall provide that no 
concentration of a pollutant shall exceed:
    (1) The concentration permitted under the national secondary ambient 
air quality standard, or
    (2) The concentration permitted under the national primary ambient 
air quality standard, whichever concentration is lowest for the 
pollutant for a period of exposure.
    (e) Restrictions on area classifications. The plan shall provide 
that--
    (1) All of the following areas which were in existence on August 7, 
1977, shall be Class I areas and may not be redesignated:
    (i) International parks,
    (ii) National wilderness areas which exceed 5,000 acres in size,
    (iii) National memorial parks which exceed 5,000 acres in size, and
    (iv) National parks which exceed 6,000 acres in size.
    (2) Areas which were redesignated as Class I under regulations 
promulgated before August 7, 1977, shall remain Class I, but may be 
redesignated as provided in this section.
    (3) Any other area, unless otherwise specified in the legislation 
creating such an area, is initially designated Class II, but may be 
redesignated as provided in this section.
    (4) The following areas may be redesignated only as Class I or II:
    (i) An area which as of August 7, 1977, exceeded 10,000 acres in 
size and was a national monument, a national primitive area, a national 
preserve, a national recreational area, a national wild and scenic 
river, a national wildlife refuge, a national lakeshore or seashore; and
    (ii) A national park or national wilderness area established after 
August 7, 1977, which exceeds 10,000 acres in size.
    (f) Exclusions from increment consumption. (1) The plan may provide 
that the following concentrations shall be excluded in determining 
compliance with a maximum allowable increase:
    (i) Concentrations attributable to the increase in emissions from 
stationary sources which have converted from the use of petroleum 
products, natural gas, or both by reason of an order in effect under 
section 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) over the 
emissions from such sources before the effective date of such an order;
    (ii) Concentrations attributable to the increase in emissions from 
sources which have converted from using natural gas by reason of natural 
gas curtailment plan in effect pursuant to the

[[Page 253]]

Federal Power Act over the emissions from such sources before the 
effective date of such plan;
    (iii) Concentrations of particulate matter attributable to the 
increase in emissions from construction or other temporary emission-
related activities of new or modified sources;
    (iv) The increase in concentrations attributable to new sources 
outside the United States over the concentrations attributable to 
existing sources which are included in the baseline concentration; and
    (v) Concentrations attributable to the temporary increase in 
emissions of sulfur dioxide, particulate matter, or nitrogen oxides from 
stationary sources which are affected by plan revisions approved by the 
Administrator as meeting the criteria specified in paragraph (f)(4) of 
this section.
    (2) If the plan provides that the concentrations to which paragraph 
(f)(1) (i) or (ii) of this section, refers shall be excluded, it shall 
also provide that no exclusion of such concentrations shall apply more 
than five years after the effective date of the order to which paragraph 
(f)(1)(i) of this section, refers or the plan to which paragraph 
(f)(1)(ii) of this section, refers, whichever is applicable. If both 
such order and plan are applicable, no such exclusion shall apply more 
than five years after the later of such effective dates.
    (3) [Reserved]
    (4) For purposes of excluding concentrations pursuant to paragraph 
(f)(1)(v) of this section, the Administrator may approve a plan revision 
that:
    (i) Specifies the time over which the temporary emissions increase 
of sulfur dioxide, particulate matter, or nitrogen oxides would occur. 
Such time is not to exceed 2 years in duration unless a longer time is 
approved by the Administrator.
    (ii) Specifies that the time period for excluding certain 
contributions in accordance with paragraph (f)(4)(i) of this section, is 
not renewable;
    (iii) Allows no emissions increase from a stationary source which 
would:
    (a) Impact a Class I area or an area where an applicable increment 
is known to be violated; or
    (b) Cause or contribute to the violation of a national ambient air 
quality standard;
    (iv) Requires limitations to be in effect the end of the time period 
specified in accordance with paragraph (f)(4)(i) of this section, which 
would ensure that the emissions levels from stationary sources affected 
by the plan revision would not exceed those levels occurring from such 
sources before the plan revision was approved.
    (g) Redesignation. (1) The plan shall provide that all areas of the 
State (except as otherwise provided under paragraph (e) of this section) 
shall be designated either Class I, Class II, or Class III. Any 
designation other than Class II shall be subject to the redesignation 
procedures of this paragraph. Redesignation (except as otherwise 
precluded by paragraph (e) of this section) may be proposed by the 
respective States or Indian Governing Bodies, as provided below, subject 
to approval by the Administrator as a revision to the applicable State 
implementation plan.
    (2) The plan may provide that the State may submit to the 
Administrator a proposal to redesignate areas of the State Class I or 
Class II: Provided, That:
    (i) At least one public hearing has been held in accordance with 
procedures established in Sec. 51.102.
    (ii) Other States, Indian Governing Bodies, and Federal Land 
Managers whose lands may be affected by the proposed redesignation were 
notified at least 30 days prior to the public hearing;
    (iii) A discussion of the reasons for the proposed redesignation, 
including a satisfactory description and analysis of the health, 
environmental, economic, social, and energy effects of the proposed 
redesignation, was prepared and made available for public inspection at 
least 30 days prior to the hearing and the notice announcing the hearing 
contained appropriate notification of the availability of such 
discussion;
    (iv) Prior to the issuance of notice respecting the redesignation of 
an area that includes any Federal lands, the State has provided written 
notice to the appropriate Federal Land Manager and afforded adequate 
opportunity (not in excess of 60 days) to confer with the

[[Page 254]]

State respecting the redesignation and to submit written comments and 
recommendations. In redesignating any area with respect to which any 
Federal Land Manager had submitted written comments and recommendations, 
the State shall have published a list of any inconsistency between such 
redesignation and such comments and recommendations (together with the 
reasons for making such redesignation against the recommendation of the 
Federal Land Manager); and
    (v) The State has proposed the redesignation after consultation with 
the elected leadership of local and other substate general purpose 
governments in the area covered by the proposed redesignation.
    (3) The plan may provide that any area other than an area to which 
paragraph (e) of this section refers may be redesignated as Class III 
if--
    (i) The redesignation would meet the requirements of provisions 
established in accordance with paragraph (g)(2) of this section;
    (ii) The redesignation, except any established by an Indian 
Governing Body, has been specifically approved by the Governor of the 
State, after consultation with the appropriate committees of the 
legislature, if it is in session, or with the leadership of the 
legislature, if it is not in session (unless State law provides that 
such redesignation must be specifically approved by State legislation) 
and if general purpose units of local government representing a majority 
of the residents of the area to be redesignated enact legislation 
(including resolutions where appropriate) concurring in the 
redesignation;
    (iii) The redesignation would not cause, or contribute to, a 
concentration of any air pollutant which would exceed any maximum 
allowable increase permitted under the classification of any other area 
or any national ambient air quality standard; and
    (iv) Any permit application for any major stationary source or major 
modification subject to provisions established in accordance with 
paragraph (l) of this section which could receive a permit only if the 
area in question were redesignated as Class III, and any material 
submitted as part of that application, were available, insofar as was 
practicable, for public inspection prior to any public hearing on 
redesignation of any area as Class III.
    (4) The plan shall provide that lands within the exterior boundaries 
of Indian Reservations may be redesignated only by the appropriate 
Indian Governing Body. The appropriate Indian Governing Body may submit 
to the Administrator a proposal to redesignate areas Class I, Class II, 
or Class III: Provided, That:
    (i) The Indian Governing Body has followed procedures equivalent to 
those required of a State under paragraphs (g) (2), (3)(iii), and 
(3)(iv) of this section; and
    (ii) Such redesignation is proposed after consultation with the 
State(s) in which the Indian Reservation is located and which border the 
Indian Reservation.
    (5) The Administrator shall disapprove, within 90 days of 
submission, a proposed redesignation of any area only if he finds, after 
notice and opportunity for public hearing, that such redesignation does 
not meet the procedural requirements of this section or is inconsistent 
with paragraph (e) of this section. If any such disapproval occurs, the 
classification of the area shall be that which was in effect prior to 
the redesignation which was disapproved.
    (6) If the Administrator disapproves any proposed area designation, 
the State or Indian Governing Body, as appropriate, may resubmit the 
proposal after correcting the deficiencies noted by the Administrator.
    (h) Stack heights. The plan shall provide, as a minimum, that the 
degree of emission limitation required for control of any air pollutant 
under the plan shall not be affected in any manner by--
    (1) So much of a stack height, not in existence before December 31, 
1970, as exceeds good engineering practice, or
    (2) Any other dispersion technique not implemented before then.
    (i) Exemptions. (1) The plan may provide that requirements 
equivalent to those contained in paragraphs (j) through (r) of this 
section do not apply to a particular major stationary source or major 
modification if:

[[Page 255]]

    (i) The major stationary source would be a nonprofit health or 
nonprofit educational institution or a major modification that would 
occur at such an institution; or
    (ii) [Reserved]
    (iii) The source or modification is a portable stationary source 
which has previously received a permit under requirements equivalent to 
those contained in paragraphs (j) through (r) of this section, if:
    (a) The source proposes to relocate and emissions of the source at 
the new location would be temporary; and
    (b) The emissions from the source would not exceed its allowable 
emissions; and
    (c) The emissions from the source would impact no Class I area and 
no area where an applicable increment is known to be violated; and
    (d) Reasonable notice is given to the reviewing authority prior to 
the relocation identifying the proposed new location and the probable 
duration of operation at the new location. Such notice shall be given to 
the reviewing authority not less than 10 days in advance of the proposed 
relocation unless a different time duration is previously approved by 
the reviewing authority.
    (2) The plan may provide that requirements equivalent to those 
contained in paragraphs (j) through (r) of this section do not apply to 
a major stationary source or major modification with respect to a 
particular pollutant if the owner or operator demonstrates that, as to 
that pollutant, the source or modification is located in an area 
designated as nonattainment under section 107 of the Act.
    (3) The plan may provide that requirements equivalent to those 
contained in paragraphs (k), (m), and (o) of this section do not apply 
to a proposed major stationary source or major modification with respect 
to a particular pollutant, if the allowable emissions of that pollutant 
from a new source, or the net emissions increase of that pollutant from 
a modification, would be temporary and impact no Class I area and no 
area where an applicable increment is known to be violated.
    (4) The plan may provide that requirements equivalent to those 
contained in paragraphs (k), (m), and (o) of this section as they relate 
to any maximum allowable increase for a Class II area do not apply to a 
modification of a major stationary source that was in existence on March 
1, 1978, if the net increase in allowable emissions of each a regulated 
NSR pollutant from the modification after the application of best 
available control technology would be less than 50 tons per year.
    (5) The plan may provide that the reviewing authority may exempt a 
proposed major stationary source or major modification from the 
requirements of paragraph (m) of this section, with respect to 
monitoring for a particular pollutant, if:
    (i) The emissions increase of the pollutant from a new stationary 
source or the net emissions increase of the pollutant from a 
modification would cause, in any area, air quality impacts less than the 
following amounts:
    (a) Carbon monoxide--575 ug/m\3\, 8-hour average;
    (b) Nitrogen dioxide--14 ug/m\3\, annual average;
    (c) Particulate matter--10 [micro]g/m\3\ of PM-10, 24-hour average.
    (d) Sulfur dioxide--13 ug/m\3\, 24-hour average;
    (e) Ozone; \1\
---------------------------------------------------------------------------

    \1\ No de minimis air quality level is provided for ozone. However, 
any net emissions increase of 100 tons per year or more of volatile 
organic compounds or nitrogen oxides subject to PSD would be required to 
perform an ambient impact analysis, including the gathering of air 
quality data.
---------------------------------------------------------------------------

    (f) Lead--0.1 [micro]g/m\3\, 3-month average.
    (g) Fluorides--0.25 [micro]g/m\3\, 24-hour average;
    (h) Total reduced sulfur--10 [micro]g/m\3\, 1-hour average
    (i) Hydrogen sulfide--0.2 [micro]g/m\3\, 1-hour average;
    (j) Reduced sulfur compounds--10 [micro]g/m\3\, 1-hour average; or
    (ii) The concentrations of the pollutant in the area that the source 
or modification would affect are less than the concentrations listed in 
paragraph (i)(5)(i) of this section; or
    (iii) The pollutant is not listed in paragraph (i)(5)(i) of this 
section.
    (6) If EPA approves a plan revision under 40 CFR 51.166 as in effect 
before August 7, 1980, any subsequent revision

[[Page 256]]

which meets the requirements of this section may contain transition 
provisions which parallel the transition provisions of 40 CFR 
52.21(i)(9), (i)(10) and (m)(1)(v) as in effect on that date, which 
provisions relate to requirements for best available control technology 
and air quality analyses. Any such subsequent revision may not contain 
any transition provision which in the context of the revision would 
operate any less stringently than would its counterpart in 40 CFR 52.21.
    (7) If EPA approves a plan revision under Sec. 51.166 as in effect 
[before July 31, 1987], any subsequent revision which meets the 
requirements of this section may contain transition provisions which 
parallel the transition provisions of Sec. 52.21 (i)(11), and (m)(1) 
(vii) and (viii) of this chapter as in effect on that date, these 
provisions being related to monitoring requirements for particulate 
matter. Any such subsequent revision may not contain any transition 
provision which in the context of the revision would operate any less 
stringently than would its counterpart in Sec. 52.21 of this chapter.
    (8) The plan may provide that the permitting requirements equivalent 
to those contained in paragraph (k)(2) of this section do not apply to a 
stationary source or modification with respect to any maximum allowable 
increase for nitrogen oxides if the owner or operator of the source or 
modification submitted an application for a permit under the applicable 
permit program approved or promulgated under the Act before the 
provisions embodying the maximum allowable increase took effect as part 
of the plan and the permitting authority subsequently determined that 
the application as submitted before that date was complete.
    (9) The plan may provide that the permitting requirements equivalent 
to those contained in paragraph (k)(2) of this section shall not apply 
to a stationary source or modification with respect to any maximum 
allowable increase for PM-10 if (i) the owner or operator of the source 
or modification submitted an application for a permit under the 
applicable permit program approved under the Act before the provisions 
embodying the maximum allowable increases for PM-10 took effect as part 
of the plan, and (ii) the permitting authority subsequently determined 
that the application as submitted before that date was complete. 
Instead, the applicable requirements equivalent to paragraph (k)(2) 
shall apply with respect to the maximum allowable increases for TSP as 
in effect on the date the application was submitted.
    (j) Control technology review. The plan shall provide that:
    (1) A major stationary source or major modification shall meet each 
applicable emissions limitation under the State Implementation Plan and 
each applicable emission standards and standard of performance under 40 
CFR parts 60 and 61.
    (2) A new major stationary source shall apply best available control 
technology for each a regulated NSR pollutant that it would have the 
potential to emit in significant amounts.
    (3) A major modification shall apply best available control 
technology for each a regulated NSR pollutant for which it would be a 
significant net emissions increase at the source. This requirement 
applies to each proposed emissions unit at which a net emissions 
increase in the pollutant would occur as a result of a physical change 
or change in the method of operation in the unit.
    (4) For phased construction projects, the determination of best 
available control technology shall be reviewed and modified as 
appropriate at the least reasonable time which occurs no later than 18 
months prior to commencement of construction of each independent phase 
of the project. At such time, the owner or operator of the applicable 
stationary source may be required to demonstrate the adequacy of any 
previous determination of best available control technology for the 
source.
    (k) Source impact analysis. The plan shall provide that the owner or 
operator of the proposed source or modification shall demonstrate that 
allowable emission increases from the proposed source or modification, 
in conjunction with all other applicable emissions increases or 
reduction (including secondary emissions) would not

[[Page 257]]

cause or contribute to air pollution in violation of:
    (1) Any national ambient air quality standard in any air quality 
control region; or
    (2) Any applicable maximum allowable increase over the baseline 
concentration in any area.
    (l) Air quality models. The plan shall provide for procedures which 
specify that--
    (1) All applications of air quality modeling involved in this 
subpart shall be based on the applicable models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a modification or 
substitution of a model may be made on a case-by-case basis or, where 
appropriate, on a generic basis for a specific State program. Written 
approval of the Administrator must be obtained for any modification or 
substitution. In addition, use of a modified or substituted model must 
be subject to notice and opportunity for public comment under procedures 
set forth in Sec. 51.102.
    (m) Air quality analysis--(1) Preapplication analysis. (i) The plan 
shall provide that any application for a permit under regulations 
approved pursuant to this section shall contain an analysis of ambient 
air quality in the area that the major stationary source or major 
modification would affect for each of the following pollutants:
    (a) For the source, each pollutant that it would have the potential 
to emit in a significant amount;
    (b) For the modification, each pollutant for which it would result 
in a significant net emissions increase.
    (ii) The plan shall provide that, with respect to any such pollutant 
for which no National Ambient Air Quality Standard exists, the analysis 
shall contain such air quality monitoring data as the reviewing 
authority determines is necessary to assess ambient air quality for that 
pollutant in any area that the emissions of that pollutant would affect.
    (iii) The plan shall provide that with respect to any such pollutant 
(other than nonmethane hydrocarbons) for which such a standard does 
exist, the analysis shall contain continuous air quality monitoring data 
gathered for purposes of determining whether emissions of that pollutant 
would cause or contribute to a violation of the standard or any maxiumum 
allowable increase.
    (iv) The plan shall provide that, in general, the continuous air 
monitoring data that is required shall have been gathered over a period 
of one year and shall represent the year preceding receipt of the 
application, except that, if the reviewing authority determines that a 
complete and adequate analysis can be accomplished with monitoring data 
gathered over a period shorter than one year (but not to be less than 
four months), the data that is required shall have been gathered over at 
least that shorter period.
    (v) The plan may provide that the owner or operator of a proposed 
major stationary source or major modification of volatile organic 
compounds who satisfies all conditions of 40 CFR part 51 appendix S, 
section IV may provide postapproval monitoring data for ozone in lieu of 
providing preconstruction data as required under paragraph (m)(1) of 
this section.
    (2) Post-construction monitoring. The plan shall provide that the 
owner or operator of a major stationary source or major modification 
shall, after construction of the stationary source or modification, 
conduct such ambient monitoring as the reviewing authority determines is 
necessary to determine the effect emissions from the stationary source 
or modification may have, or are having, on air quality in any area.
    (3) Operation of monitoring stations. The plan shall provide that 
the owner or operator of a major stationary source or major modification 
shall meet the requirements of appendix B to part 58 of this chapter 
during the operation of monitoring stations for purposes of satisfying 
paragraph (m) of this section.

[[Page 258]]

    (n) Source information. (1) The plan shall provide that the owner or 
operator of a proposed source or modification shall submit all 
information necessary to perform any analysis or make any determination 
required under procedures established in accordance with this section.
    (2) The plan may provide that such information shall include:
    (i) A description of the nature, location, design capacity, and 
typical operating schedule of the source or modification, including 
specifications and drawings showing its design and plant layout;
    (ii) A detailed schedule for construction of the source or 
modification;
    (iii) A detailed description as to what system of continuous 
emission reduction is planned by the source or modification, emission 
estimates, and any other information as necessary to determine that best 
available control technology as applicable would be applied;
    (3) The plan shall provide that upon request of the State, the owner 
or operator shall also provide information on:
    (i) The air quality impact of the source or modification, including 
meteorological and topographical data necessary to estimate such impact; 
and
    (ii) The air quality impacts and the nature and extent of any or all 
general commercial, residential, industrial, and other growth which has 
occurred since August 7, 1977, in the area the source or modification 
would affect.
    (o) Additional impact analyses. The plan shall provide that--
    (1) The owner or operator shall provide an analysis of the 
impairment to visibility, soils, and vegetation that would occur as a 
result of the source or modification and general commercial, 
residential, industrial, and other growth associated with the source or 
modification. The owner or operator need not provide an analysis of the 
impact on vegetation having no significant commercial or recreational 
value.
    (2) The owner or operator shall provide an analysis of the air 
quality impact projected for the area as a result of general commercial, 
residential, industrial, and other growth associated with the source or 
modification.
    (p) Sources impacting Federal Class I areas--additional 
requirements--(1) Notice to EPA. The plan shall provide that the 
reviewing authority shall transmit to the Administrator a copy of each 
permit application relating to a major stationary source or major 
modification and provide notice to the Administrator of every action 
related to the consideration of such permit.
    (2) Federal Land Manager. The Federal Land Manager and the Federal 
official charged with direct responsibility for management of Class I 
lands have an affirmative responsibility to protect the air quality 
related values (including visibility) of any such lands and to consider, 
in consultation with the Administrator, whether a proposed source or 
modification would have an adverse impact on such values.
    (3) Denial--impact on air quality related values. The plan shall 
provide a mechanism whereby a Federal Land Manager of any such lands may 
present to the State, after the reviewing authority's preliminary 
determination required under procedures developed in accordance with 
paragraph (r) of this section, a demonstration that the emissions from 
the proposed source or modification would have an adverse impact on the 
air quality-related values (including visibility) of any Federal 
mandatory Class I lands, notwithstanding that the change in air quality 
resulting from emissions from such source or modification would not 
cause or contribute to concentrations which would exceed the maximum 
allowable increases for a Class I area. If the State concurs with such 
demonstration, the reviewing authority shall not issue the permit.
    (4) Class I Variances. The plan may provide that the owner or 
operator of a proposed source or modification may demonstrate to the 
Federal Land Manager that the emissions from such source would have no 
adverse impact on the air quality related values of such lands 
(including visibility), notwithstanding that the change in air quality 
resulting from emissions from such source or modification would cause or 
contribute to concentrations which would exceed the maximum allowable 
increases for a Class I area. If the Federal land manager concurs with

[[Page 259]]

such demonstration and so certifies to the State, the reviewing 
authority may: Provided, That applicable requirements are otherwise met, 
issue the permit with such emission limitations as may be necessary to 
assure that emissions of sulfur dioxide, particulate matter, and 
nitrogen oxides would not exceed the following maximum allowable 
increases over minor source baseline concentration for such pollutants:

------------------------------------------------------------------------
                                                               Maximum
                                                              allowable
                                                               increase
                         Pollutant                           (micrograms
                                                              per cubic
                                                                meter)
------------------------------------------------------------------------
Particulate matter:
    PM-10, annual arithmetic mean..........................         17
    PM-10, 24-hour maximum.................................         30
Sulfur dioxide:
    Annual arithmetic mean.................................         20
    24-hr maximum..........................................         91
    3-hr maximum...........................................        325
Nitrogen dioxide: Annual arithmetic mean...................         25
------------------------------------------------------------------------

    (5) Sulfur dioxide variance by Governor with Federal Land Manager's 
concurrence. The plan may provide that--
    (i) The owner or operator of a proposed source or modification which 
cannot be approved under procedures developed pursuant to paragraph 
(q)(4) of this section may demonstrate to the Governor that the source 
or modification cannot be constructed by reason of any maximum allowable 
increase for sulfur dioxide for periods of twenty-four hours or less 
applicable to any Class I area and, in the case of Federal mandatory 
Class I areas, that a variance under this clause would not adversely 
affect the air quality related values of the area (including 
visibility);
    (ii) The Governor, after consideration of the Federal Land Manager's 
recommendation (if any) and subject to his concurrence, may grant, after 
notice and an opportunity for a public hearing, a variance from such 
maximum allowable increase; and
    (iii) If such variance is granted, the reviewing authority may issue 
a permit to such source or modification in accordance with provisions 
developed pursuant to paragraph (q)(7) of this section: Provided, That 
the applicable requirements of the plan are otherwise met.
    (6) Variance by the Governor with the President's concurrence. The 
plan may provide that--
    (i) The recommendations of the Governor and the Federal Land Manager 
shall be transferred to the President in any case where the Governor 
recommends a variance in which the Federal Land Manager does not concur;
    (ii) The President may approve the Governor's recommendation if he 
finds that such variance is in the national interest; and
    (iii) If such a variance is approved, the reviewing authority may 
issue a permit in accordance with provisions developed pursuant to the 
requirements of paragraph (q)(7) of this section: Provided, That the 
applicable requirements of the plan are otherwise met.
    (7) Emission limitations for Presidential or gubernatorial variance. 
The plan shall provide that in the case of a permit issued under 
procedures developed pursuant to paragraph (q) (5) or (6) of this 
section, the source or modification shall comply with emission 
limitations as may be necessary to assure that emissions of sulfur 
dioxide from the source or modification would not (during any day on 
which the otherwise applicable maximum allowable increases are exceeded) 
cause or contribute to concentrations which would exceed the following 
maximum allowable increases over the baseline concentration and to 
assure that such emissions would not cause or contribute to 
concentrations which exceed the otherwise applicable maximum allowable 
increases for periods of exposure of 24 hours or less for more than 18 
days, not necessarily consecutive, during any annual period:

                       Maximum Allowable Increase
                      [Micrograms per cubic meter]
------------------------------------------------------------------------
                                                          Terrain areas
                  Period of exposure                   -----------------
                                                          Low      High
------------------------------------------------------------------------
24-hr maximum.........................................       36       62
3-hr maximum..........................................      130      221
------------------------------------------------------------------------

    (q) Public participation. The plan shall provide that--
    (1) The reviewing authority shall notify all applicants within a 
specified time period as to the completeness of

[[Page 260]]

the application or any deficiency in the application or information 
submitted. In the event of such a deficiency, the date of receipt of the 
application shall be the date on which the reviewing authority received 
all required information.
    (2) Within one year after receipt of a complete application, the 
reviewing authority shall:
    (i) Make a preliminary determination whether construction should be 
approved, approved with conditions, or disapproved.
    (ii) Make available in at least one location in each region in which 
the proposed source would be constructed a copy of all materials the 
applicant submitted, a copy of the preliminary determination, and a copy 
or summary of other materials, if any, considered in making the 
preliminary determination.
    (iii) Notify the public, by advertisement in a newspaper of general 
circulation in each region in which the proposed source would be 
constructed, of the application, the preliminary determination, the 
degree of increment consumption that is expected from the source or 
modification, and of the opportunity for comment at a public hearing as 
well as written public comment.
    (iv) Send a copy of the notice of public comment to the applicant, 
the Administrator and to officials and agencies having cognizance over 
the location where the proposed construction would occur as follows: Any 
other State or local air pollution control agencies, the chief 
executives of the city and county where the source would be located; any 
comprehensive regional land use planning agency, and any State, Federal 
Land Manager, or Indian Governing body whose lands may be affected by 
emissions from the source or modification.
    (v) Provide opportunity for a public hearing for interested persons 
to appear and submit written or oral comments on the air quality impact 
of the source, alternatives to it, the control technology required, and 
other appropriate considerations.
    (vi) Consider all written comments submitted within a time specified 
in the notice of public comment and all comments received at any public 
hearing(s) in making a final decision on the approvability of the 
application. The reviewing authority shall make all comments available 
for public inspection in the same locations where the reviewing 
authority made available preconstruction information relating to the 
proposed source or modification.
    (vii) Make a final determination whether construction should be 
approved, approved with conditions, or disapproved.
    (viii) Notify the applicant in writing of the final determination 
and make such notification available for public inspection at the same 
location where the reviewing authority made available preconstruction 
information and public comments relating to the source.
    (r) Source obligation. (1) The plan shall include enforceable 
procedures to provide that approval to construct shall not relieve any 
owner or operator of the responsibility to comply fully with applicable 
provisions of the plan and any other requirements under local, State or 
Federal law.
    (2) The plan shall provide that at such time that a particular 
source or modification becomes a major stationary source or major 
modification solely by virtue of a relaxation in any enforceable 
limitation which was established after August 7, 1980, on the capacity 
of the source or modification otherwise to emit a pollutant, such as a 
restriction on hours of operation, then the requirements of paragraphs 
(j) through (s) of this section shall apply to the source or 
modification as though construction had not yet commenced on the source 
or modification.
    (3)-(5) [Reserved]
    (6) Each plan shall provide that, except as otherwise provided in 
paragraph (r)(6)(vi) of this section, the following specific provisions 
apply with respect to any regulated NSR pollutant emitted from projects 
at existing emissions units at a major stationary source (other than 
projects at a source with a PAL) in circumstances where there is a 
reasonable possibility, within the meaning of paragraph (r)(6)(vi) of 
this section, that a project that is not a part of a major modification 
may result in a significant emissions increase

[[Page 261]]

of such pollutant, and the owner or operator elects to use the method 
specified in paragraphs (b)(40)(ii)(a) through (c) of this section for 
calculating projected actual emissions. Deviations from these provisions 
will be approved only if the State specifically demonstrates that the 
submitted provisions are more stringent than or at least as stringent in 
all respects as the corresponding provisions in paragraphs (r)(6)(i) 
through (vi) of this section.
    (i) Before beginning actual construction of the project, the owner 
or operator shall document and maintain a record of the following 
information:
    (a) A description of the project;
    (b) Identification of the emissions unit(s) whose emissions of a 
regulated NSR pollutant could be affected by the project; and
    (c) A description of the applicability test used to determine that 
the project is not a major modification for any regulated NSR pollutant, 
including the baseline actual emissions, the projected actual emissions, 
the amount of emissions excluded under paragraph (b)(40)(ii)(c) of this 
section and an explanation for why such amount was excluded, and any 
netting calculations, if applicable.
    (ii) If the emissions unit is an existing electric utility steam 
generating unit, before beginning actual construction, the owner or 
operator shall provide a copy of the information set out in paragraph 
(r)(6)(i) of this section to the reviewing authority. Nothing in this 
paragraph (r)(6)(ii) shall be construed to require the owner or operator 
of such a unit to obtain any determination from the reviewing authority 
before beginning actual construction.
    (iii) The owner or operator shall monitor the emissions of any 
regulated NSR pollutant that could increase as a result of the project 
and that is emitted by any emissions unit identified in paragraph 
(r)(6)(i)(b) of this section; and calculate and maintain a record of the 
annual emissions, in tons per year on a calendar year basis, for a 
period of 5 years following resumption of regular operations after the 
change, or for a period of 10 years following resumption of regular 
operations after the change if the project increases the design capacity 
or potential to emit of that regulated NSR pollutant at such emissions 
unit. For purposes of this paragraph (r)(6)(iii), fugitive emissions (to 
the extent quantifiable) shall be monitored if the emissions unit is 
part of one of the source categories listed in paragraph (b)(1)(iii) of 
this section or if the emissions unit is located at a major stationary 
source that belongs to one of the listed source categories.
    (iv) If the unit is an existing electric utility steam generating 
unit, the owner or operator shall submit a report to the reviewing 
authority within 60 days after the end of each year during which records 
must be generated under paragraph (r)(6)(iii) of this section setting 
out the unit's annual emissions, as monitored pursuant to paragraph 
(r)(6)(iii) of this section, during the calendar year that preceded 
submission of the report.
    (v) If the unit is an existing unit other than an electric utility 
steam generating unit, the owner or operator shall submit a report to 
the reviewing authority if the annual emissions, in tons per year, from 
the project identified in paragraph (r)(6)(i) of this section, exceed 
the baseline actual emissions (as documented and maintained pursuant to 
paragraph (r)(6)(i)(c) of this section) by a significant amount (as 
defined in paragraph (b)(23) of this section) for that regulated NSR 
pollutant, and if such emissions differ from the preconstruction 
projection as documented and maintained pursuant to paragraph 
(r)(6)(i)(c) of this section. Such report shall be submitted to the 
reviewing authority within 60 days after the end of such year. The 
report shall contain the following:
    (a) The name, address and telephone number of the major stationary 
source;
    (b) The annual emissions as calculated pursuant to paragraph 
(r)(6)(iii) of this section; and
    (c) Any other information that the owner or operator wishes to 
include in the report (e.g., an explanation as to why the emissions 
differ from the preconstruction projection).
    (vi) A ``reasonable possibility'' under paragraph (r)(6) of this 
section occurs when the owner or operator calculates the project to 
result in either:
    (a) A projected actual emissions increase of at least 50 percent of 
the

[[Page 262]]

amount that is a ``significant emissions increase,'' as defined under 
paragraph (b)(39) of this section (without reference to the amount that 
is a significant net emissions increase), for the regulated NSR 
pollutant; or
    (b) A projected actual emissions increase that, added to the amount 
of emissions excluded under paragraph (b)(40)(ii)(c), sums to at least 
50 percent of the amount that is a ``significant emissions increase,'' 
as defined under paragraph (b)(39) of this section (without reference to 
the amount that is a significant net emissions increase), for the 
regulated NSR pollutant. For a project for which a reasonable 
possibility occurs only within the meaning of paragraph (r)(6)(vi)(b) of 
this section, and not also within the meaning of paragraph (a)(6)(vi)(a) 
of this section, then provisions (a)(6)(ii) through (v) do not apply to 
the project.
    (7) Each plan shall provide that the owner or operator of the source 
shall make the information required to be documented and maintained 
pursuant to paragraph (r)(6) of this section available for review upon 
request for inspection by the reviewing authority or the general public 
pursuant to the requirements contained in Sec. 70.4(b)(3)(viii) of this 
chapter.
    (s) Innovative control technology. (1) The plan may provide that an 
owner or operator of a proposed major stationary source or major 
modification may request the reviewing authority to approve a system of 
innovative control technology.
    (2) The plan may provide that the reviewing authority may, with the 
consent of the Governor(s) of other affected State(s), determine that 
the source or modification may employ a system of innovative control 
technology, if:
    (i) The proposed control system would not cause or contribute to an 
unreasonable risk to public health, welfare, or safety in its operation 
or function;
    (ii) The owner or operator agrees to achieve a level of continuous 
emissions reduction equivalent to that which would have been required 
under paragraph (j)(2) of this section, by a date specified by the 
reviewing authority. Such date shall not be later than 4 years from the 
time of startup or 7 years from permit issuance;
    (iii) The source or modification would meet the requirements 
equivalent to those in paragraphs (j) and (k) of this section, based on 
the emissions rate that the stationary source employing the system of 
innovative control technology would be required to meet on the date 
specified by the reviewing authority;
    (iv) The source or modification would not before the date specified 
by the reviewing authority:
    (a) Cause or contribute to any violation of an applicable national 
ambient air quality standard; or
    (b) Impact any area where an applicable increment is known to be 
violated;
    (v) All other applicable requirements including those for public 
participation have been met.
    (vi) The provisions of paragraph (p) of this section (relating to 
Class I areas) have been satisfied with respect to all periods during 
the life of the source or modification.
    (3) The plan shall provide that the reviewing authority shall 
withdraw any approval to employ a system of innovative control 
technology made under this section, if:
    (i) The proposed system fails by the specified date to achieve the 
required continuous emissions reduction rate; or
    (ii) The proposed system fails before the specified date so as to 
contribute to an unreasonable risk to public health, welfare, or safety; 
or
    (iii) The reviewing authority decides at any time that the proposed 
system is unlikely to achieve the required level of control or to 
protect the public health, welfare, or safety.
    (4) The plan may provide that if a source or modification fails to 
meet the required level of continuous emissions reduction within the 
specified time period, or if the approval is withdrawn in accordance 
with paragraph (s)(3) of this section, the reviewing authority may allow 
the source or modification up to an additional 3 years to meet the 
requirement for the application of best available control technology 
through use of a demonstrated system of control.
    (t)-(v) [Reserved]

[[Page 263]]

    (w) Actuals PALs. The plan shall provide for PALs according to the 
provisions in paragraphs (w)(1) through (15) of this section.
    (1) Applicability. (i) The reviewing authority may approve the use 
of an actuals PAL for any existing major stationary source if the PAL 
meets the requirements in paragraphs (w)(1) through (15) of this 
section. The term ``PAL'' shall mean ``actuals PAL'' throughout 
paragraph (w) of this section.
    (ii) Any physical change in or change in the method of operation of 
a major stationary source that maintains its total source-wide emissions 
below the PAL level, meets the requirements in paragraphs (w)(1) through 
(15) of this section, and complies with the PAL permit:
    (a) Is not a major modification for the PAL pollutant;
    (b) Does not have to be approved through the plan's major NSR 
program; and
    (c) Is not subject to the provisions in paragraph (r)(2) of this 
section (restrictions on relaxing enforceable emission limitations that 
the major stationary source used to avoid applicability of the major NSR 
program).
    (iii) Except as provided under paragraph (w)(1)(ii)(c) of this 
section, a major stationary source shall continue to comply with all 
applicable Federal or State requirements, emission limitations, and work 
practice requirements that were established prior to the effective date 
of the PAL.
    (2) Definitions. The plan shall use the definitions in paragraphs 
(w)(2)(i) through (xi) of this section for the purpose of developing and 
implementing regulations that authorize the use of actuals PALs 
consistent with paragraphs (w)(1) through (15) of this section. When a 
term is not defined in these paragraphs, it shall have the meaning given 
in paragraph (b) of this section or in the Act.
    (i) Actuals PAL for a major stationary source means a PAL based on 
the baseline actual emissions (as defined in paragraph (b)(47) of this 
section) of all emissions units (as defined in paragraph (b)(7) of this 
section) at the source, that emit or have the potential to emit the PAL 
pollutant.
    (ii) Allowable emissions means ``allowable emissions'' as defined in 
paragraph (b)(16) of this section, except as this definition is modified 
according to paragraphs (w)(2)(ii)(a) and (b) of this section.
    (a) The allowable emissions for any emissions unit shall be 
calculated considering any emission limitations that are enforceable as 
a practical matter on the emissions unit's potential to emit.
    (b) An emissions unit's potential to emit shall be determined using 
the definition in paragraph (b)(4) of this section, except that the 
words ``or enforceable as a practical matter'' should be added after 
``federally enforceable.''
    (iii) Small emissions unit means an emissions unit that emits or has 
the potential to emit the PAL pollutant in an amount less than the 
significant level for that PAL pollutant, as defined in paragraph 
(b)(23) of this section or in the Act, whichever is lower.
    (iv) Major emissions unit means:
    (a) Any emissions unit that emits or has the potential to emit 100 
tons per year or more of the PAL pollutant in an attainment area; or
    (b) Any emissions unit that emits or has the potential to emit the 
PAL pollutant in an amount that is equal to or greater than the major 
source threshold for the PAL pollutant as defined by the Act for 
nonattainment areas. For example, in accordance with the definition of 
major stationary source in section 182(c) of the Act, an emissions unit 
would be a major emissions unit for VOC if the emissions unit is located 
in a serious ozone nonattainment area and it emits or has the potential 
to emit 50 or more tons of VOC per year.
    (v) Plantwide applicability limitation (PAL) means an emission 
limitation expressed in tons per year, for a pollutant at a major 
stationary source, that is enforceable as a practical matter and 
established source-wide in accordance with paragraphs (w)(1) through 
(15) of this section.
    (vi) PAL effective date generally means the date of issuance of the 
PAL permit. However, the PAL effective date for an increased PAL is the 
date any emissions unit that is part of the

[[Page 264]]

PAL major modification becomes operational and begins to emit the PAL 
pollutant.
    (vii) PAL effective period means the period beginning with the PAL 
effective date and ending 10 years later.
    (viii) PAL major modification means, notwithstanding paragraphs 
(b)(2) and (b)(3) of this section (the definitions for major 
modification and net emissions increase), any physical change in or 
change in the method of operation of the PAL source that causes it to 
emit the PAL pollutant at a level equal to or greater than the PAL.
    (ix) PAL permit means the major NSR permit, the minor NSR permit, or 
the State operating permit under a program that is approved into the 
plan, or the title V permit issued by the reviewing authority that 
establishes a PAL for a major stationary source.
    (x) PAL pollutant means the pollutant for which a PAL is established 
at a major stationary source.
    (xi) Significant emissions unit means an emissions unit that emits 
or has the potential to emit a PAL pollutant in an amount that is equal 
to or greater than the significant level (as defined in paragraph 
(b)(23) of this section or in the Act, whichever is lower) for that PAL 
pollutant, but less than the amount that would qualify the unit as a 
major emissions unit as defined in paragraph (w)(2)(iv) of this section.
    (3) Permit application requirements. As part of a permit application 
requesting a PAL, the owner or operator of a major stationary source 
shall submit the following information in paragraphs (w)(3)(i) through 
(iii) of this section to the reviewing authority for approval.
    (i) A list of all emissions units at the source designated as small, 
significant or major based on their potential to emit. In addition, the 
owner or operator of the source shall indicate which, if any, Federal or 
State applicable requirements, emission limitations, or work practices 
apply to each unit.
    (ii) Calculations of the baseline actual emissions (with supporting 
documentation). Baseline actual emissions are to include emissions 
associated not only with operation of the unit, but also emissions 
associated with startup, shutdown, and malfunction.
    (iii) The calculation procedures that the major stationary source 
owner or operator proposes to use to convert the monitoring system data 
to monthly emissions and annual emissions based on a 12-month rolling 
total for each month as required by paragraph (w)(13)(i) of this 
section.
    (4) General requirements for establishing PALs. (i) The plan allows 
the reviewing authority to establish a PAL at a major stationary source, 
provided that at a minimum, the requirements in paragraphs (w)(4)(i)(a) 
through (g) of this section are met.
    (a) The PAL shall impose an annual emission limitation in tons per 
year, that is enforceable as a practical matter, for the entire major 
stationary source. For each month during the PAL effective period after 
the first 12 months of establishing a PAL, the major stationary source 
owner or operator shall show that the sum of the monthly emissions from 
each emissions unit under the PAL for the previous 12 consecutive months 
is less than the PAL (a 12-month average, rolled monthly). For each 
month during the first 11 months from the PAL effective date, the major 
stationary source owner or operator shall show that the sum of the 
preceding monthly emissions from the PAL effective date for each 
emissions unit under the PAL is less than the PAL.
    (b) The PAL shall be established in a PAL permit that meets the 
public participation requirements in paragraph (w)(5) of this section.
    (c) The PAL permit shall contain all the requirements of paragraph 
(w)(7) of this section.
    (d) The PAL shall include fugitive emissions, to the extent 
quantifiable, from all emissions units that emit or have the potential 
to emit the PAL pollutant at the major stationary source, regardless of 
whether the emissions unit or major stationary source belongs to one of 
the source categories listed in paragraph (b)(1)(iii) of this section.
    (e) Each PAL shall regulate emissions of only one pollutant.
    (f) Each PAL shall have a PAL effective period of 10 years.
    (g) The owner or operator of the major stationary source with a PAL

[[Page 265]]

shall comply with the monitoring, recordkeeping, and reporting 
requirements provided in paragraphs (w)(12) through (14) of this section 
for each emissions unit under the PAL through the PAL effective period.
    (ii) At no time (during or after the PAL effective period) are 
emissions reductions of a PAL pollutant that occur during the PAL 
effective period creditable as decreases for purposes of offsets under 
Sec. 51.165(a)(3)(ii) of this chapter unless the level of the PAL is 
reduced by the amount of such emissions reductions and such reductions 
would be creditable in the absence of the PAL.
    (5) Public participation requirements for PALs. PALs for existing 
major stationary sources shall be established, renewed, or increased, 
through a procedure that is consistent with Sec. Sec. 51.160 and 51.161 
of this chapter. This includes the requirement that the reviewing 
authority provide the public with notice of the proposed approval of a 
PAL permit and at least a 30-day period for submittal of public comment. 
The reviewing authority must address all material comments before taking 
final action on the permit.
    (6) Setting the 10-year actuals PAL level. (i) Except as provided in 
paragraph (w)(6)(ii) of this section, the plan shall provide that the 
actuals PAL level for a major stationary source shall be established as 
the sum of the baseline actual emissions (as defined in paragraph 
(b)(47) of this section) of the PAL pollutant for each emissions unit at 
the source; plus an amount equal to the applicable significant level for 
the PAL pollutant under paragraph (b)(23) of this section or under the 
Act, whichever is lower. When establishing the actuals PAL level, for a 
PAL pollutant, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for all existing emissions 
units. However, a different consecutive 24-month period may be used for 
each different PAL pollutant. Emissions associated with units that were 
permanently shut down after this 24-month period must be subtracted from 
the PAL level. The reviewing authority shall specify a reduced PAL 
level(s) (in tons/yr) in the PAL permit to become effective on the 
future compliance date(s) of any applicable Federal or State regulatory 
requirement(s) that the reviewing authority is aware of prior to 
issuance of the PAL permit. For instance, if the source owner or 
operator will be required to reduce emissions from industrial boilers in 
half from baseline emissions of 60 ppm NOX to a new rule 
limit of 30 ppm, then the permit shall contain a future effective PAL 
level that is equal to the current PAL level reduced by half of the 
original baseline emissions of such unit(s).
    (ii) For newly constructed units (which do not include modifications 
to existing units) on which actual construction began after the 24-month 
period, in lieu of adding the baseline actual emissions as specified in 
paragraph (w)(6)(i) of this section, the emissions must be added to the 
PAL level in an amount equal to the potential to emit of the units.
    (7) Contents of the PAL permit. The plan shall require that the PAL 
permit contain, at a minimum, the information in paragraphs (w)(7)(i) 
through (x) of this section.
    (i) The PAL pollutant and the applicable source-wide emission 
limitation in tons per year.
    (ii) The PAL permit effective date and the expiration date of the 
PAL (PAL effective period).
    (iii) Specification in the PAL permit that if a major stationary 
source owner or operator applies to renew a PAL in accordance with 
paragraph (w)(10) of this section before the end of the PAL effective 
period, then the PAL shall not expire at the end of the PAL effective 
period. It shall remain in effect until a revised PAL permit is issued 
by the reviewing authority.
    (iv) A requirement that emission calculations for compliance 
purposes include emissions from startups, shutdowns and malfunctions.
    (v) A requirement that, once the PAL expires, the major stationary 
source is subject to the requirements of paragraph (w)(9) of this 
section.
    (vi) The calculation procedures that the major stationary source 
owner or operator shall use to convert the monitoring system data to 
monthly emissions and annual emissions based on a 12-month rolling total 
for each month

[[Page 266]]

as required by paragraph (w)(3)(i) of this section.
    (vii) A requirement that the major stationary source owner or 
operator monitor all emissions units in accordance with the provisions 
under paragraph (w)(13) of this section.
    (viii) A requirement to retain the records required under paragraph 
(w)(13) of this section on site. Such records may be retained in an 
electronic format.
    (ix) A requirement to submit the reports required under paragraph 
(w)(14) of this section by the required deadlines.
    (x) Any other requirements that the reviewing authority deems 
necessary to implement and enforce the PAL.
    (8) PAL effective period and reopening of the PAL permit. The plan 
shall require the information in paragraphs (w)(8)(i) and (ii) of this 
section.
    (i) PAL effective period. The reviewing authority shall specify a 
PAL effective period of 10 years.
    (ii) Reopening of the PAL permit. (a) During the PAL effective 
period, the plan shall require the reviewing authority to reopen the PAL 
permit to:
    (1) Correct typographical/calculation errors made in setting the PAL 
or reflect a more accurate determination of emissions used to establish 
the PAL;
    (2) Reduce the PAL if the owner or operator of the major stationary 
source creates creditable emissions reductions for use as offsets under 
Sec. 51.165(a)(3)(ii) of this chapter; and
    (3) Revise the PAL to reflect an increase in the PAL as provided 
under paragraph (w)(11) of this section.
    (b) The plan shall provide the reviewing authority discretion to 
reopen the PAL permit for the following:
    (1) Reduce the PAL to reflect newly applicable Federal requirements 
(for example, NSPS) with compliance dates after the PAL effective date;
    (2) Reduce the PAL consistent with any other requirement, that is 
enforceable as a practical matter, and that the State may impose on the 
major stationary source under the plan; and
    (3) Reduce the PAL if the reviewing authority determines that a 
reduction is necessary to avoid causing or contributing to a NAAQS or 
PSD increment violation, or to an adverse impact on an AQRV that has 
been identified for a Federal Class I area by a Federal Land Manager and 
for which information is available to the general public.
    (c) Except for the permit reopening in paragraph (w)(8)(ii)(a)(1) of 
this section for the correction of typographical/calculation errors that 
do not increase the PAL level, all reopenings shall be carried out in 
accordance with the public participation requirements of paragraph 
(w)(5) of this section.
    (9) Expiration of a PAL. Any PAL that is not renewed in accordance 
with the procedures in paragraph (w)(10) of this section shall expire at 
the end of the PAL effective period, and the requirements in paragraphs 
(w)(9)(i) through (v) of this section shall apply.
    (i) Each emissions unit (or each group of emissions units) that 
existed under the PAL shall comply with an allowable emission limitation 
under a revised permit established according to the procedures in 
paragraphs (w)(9)(i)(a) and (b) of this section.
    (a) Within the time frame specified for PAL renewals in paragraph 
(w)(10)(ii) of this section, the major stationary source shall submit a 
proposed allowable emission limitation for each emissions unit (or each 
group of emissions units, if such a distribution is more appropriate as 
decided by the reviewing authority) by distributing the PAL allowable 
emissions for the major stationary source among each of the emissions 
units that existed under the PAL. If the PAL had not yet been adjusted 
for an applicable requirement that became effective during the PAL 
effective period, as required under paragraph (w)(10)(v) of this 
section, such distribution shall be made as if the PAL had been 
adjusted.
    (b) The reviewing authority shall decide whether and how the PAL 
allowable emissions will be distributed and issue a revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as the reviewing authority determines is appropriate.
    (ii) Each emissions unit(s) shall comply with the allowable emission 
limitation on a 12-month rolling basis. The reviewing authority may 
approve the

[[Page 267]]

use of monitoring systems (source testing,emission factors, etc.) other 
than CEMS, CERMS, PEMS or CPMS to demonstrate compliance with the 
allowable emission limitation.
    (iii) Until the reviewing authority issues the revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as required under paragraph (w)(9)(i)(b) of this 
section, the source shall continue to comply with a source-wide, multi-
unit emissions cap equivalent to the level of the PAL emission 
limitation.
    (iv) Any physical change or change in the method of operation at the 
major stationary source will be subject to major NSR requirements if 
such change meets the definition of major modification in paragraph 
(b)(2) of this section.
    (v) The major stationary source owner or operator shall continue to 
comply with any State or Federal applicable requirements (BACT, RACT, 
NSPS, etc.) that may have applied either during the PAL effective period 
or prior to the PAL effective period except for those emission 
limitations that had been established pursuant to paragraph (r)(2) of 
this section, but were eliminated by the PAL in accordance with the 
provisions in paragraph (w)(1)(ii)(c) of this section.
    (10) Renewal of a PAL. (i) The reviewing authority shall follow the 
procedures specified in paragraph (w)(5) of this section in approving 
any request to renew a PAL for a major stationary source, and shall 
provide both the proposed PAL level and a written rationale for the 
proposed PAL level to the public for review and comment. During such 
public review, any person may propose a PAL level for the source for 
consideration by the reviewing authority.
    (ii) Application deadline. The plan shall require that a major 
stationary source owner or operator shall submit a timely application to 
the reviewing authority to request renewal of a PAL. A timely 
application is one that is submitted at least 6 months prior to, but not 
earlier than 18 months from, the date of permit expiration. This 
deadline for application submittal is to ensure that the permit will not 
expire before the permit is renewed. If the owner or operator of a major 
stationary source submits a complete application to renew the PAL within 
this time period, then the PAL shall continue to be effective until the 
revised permit with the renewed PAL is issued.
    (iii) Application requirements. The application to renew a PAL 
permit shall contain the information required in paragraphs (w)(10)(iii) 
(a) through (d) of this section.
    (a) The information required in paragraphs (w)(3)(i) through (iii) 
of this section.
    (b) A proposed PAL level.
    (c) The sum of the potential to emit of all emissions units under 
the PAL (with supporting documentation).
    (d) Any other information the owner or operator wishes the reviewing 
authority to consider in determining the appropriate level for renewing 
the PAL.
    (iv) PAL adjustment. In determining whether and how to adjust the 
PAL, the reviewing authority shall consider the options outlined in 
paragraphs (w)(10)(iv) (a) and (b) of this section. However, in no case 
may any such adjustment fail to comply with paragraph (w)(10)(iv)(c) of 
this section.
    (a) If the emissions level calculated in accordance with paragraph 
(w)(6) of this section is equal to or greater than 80 percent of the PAL 
level, the reviewing authority may renew the PAL at the same level 
without considering the factors set forth in paragraph (w)(10)(iv)(b) of 
this section; or
    (b) The reviewing authority may set the PAL at a level that it 
determines to be more representative of the source's baseline actual 
emissions, or that it determines to be appropriate considering air 
quality needs, advances in control technology, anticipated economic 
growth in the area, desire to reward or encourage the source's voluntary 
emissions reductions, or other factors as specifically identified by the 
reviewing authority in its written rationale.
    (c) Notwithstanding paragraphs (w)(10)(iv) (a) and (b) of this 
section:
    (1) If the potential to emit of the major stationary source is less 
than the PAL, the reviewing authority shall adjust the PAL to a level no 
greater

[[Page 268]]

than the potential to emit of the source; and
    (2) The reviewing authority shall not approve a renewed PAL level 
higher than the current PAL, unless the major stationary source has 
complied with the provisions of paragraph (w)(11) of this section 
(increasing a PAL).
    (v) If the compliance date for a State or Federal requirement that 
applies to the PAL source occurs during the PAL effective period, and if 
the reviewing authority has not already adjusted for such requirement, 
the PAL shall be adjusted at the time of PAL permit renewal or title V 
permit renewal, whichever occurs first.
    (11) Increasing a PAL during the PAL effective period. (i) The plan 
shall require that the reviewing authority may increase a PAL emission 
limitation only if the major stationary source complies with the 
provisions in paragraphs (w)(11)(i) (a) through (d) of this section.
    (a) The owner or operator of the major stationary source shall 
submit a complete application to request an increase in the PAL limit 
for a PAL major modification. Such application shall identify the 
emissions unit(s) contributing to the increase in emissions so as to 
cause the major stationary source's emissions to equal or exceed its 
PAL.
    (b) As part of this application, the major stationary source owner 
or operator shall demonstrate that the sum of the baseline actual 
emissions of the small emissions units, plus the sum of the baseline 
actual emissions of the significant and major emissions units assuming 
application of BACT equivalent controls, plus the sum of the allowable 
emissions of the new or modified emissions unit(s), exceeds the PAL. The 
level of control that would result from BACT equivalent controls on each 
significant or major emissions unit shall be determined by conducting a 
new BACT analysis at the time the application is submitted, unless the 
emissions unit is currently required to comply with a BACT or LAER 
requirement that was established within the preceding 10 years. In such 
a case, the assumed control level for that emissions unit shall be equal 
to the level of BACT or LAER with which that emissions unit must 
currently comply.
    (c) The owner or operator obtains a major NSR permit for all 
emissions unit(s) identified in paragraph (w)(11)(i)(a) of this section, 
regardless of the magnitude of the emissions increase resulting from 
them (that is, no significant levels apply). These emissions unit(s) 
shall comply with any emissions requirements resulting from the major 
NSR process (for example, BACT), even though they have also become 
subject to the PAL or continue to be subject to the PAL.
    (d) The PAL permit shall require that the increased PAL level shall 
be effective on the day any emissions unit that is part of the PAL major 
modification becomes operational and begins to emit the PAL pollutant.
    (ii) The reviewing authority shall calculate the new PAL as the sum 
of the allowable emissions for each modified or new emissions unit, plus 
the sum of the baseline actual emissions of the significant and major 
emissions units (assuming application of BACT equivalent controls as 
determined in accordance with paragraph (w)(11)(i)(b) of this section), 
plus the sum of the baseline actual emissions of the small emissions 
units.
    (iii) The PAL permit shall be revised to reflect the increased PAL 
level pursuant to the public notice requirements of paragraph (w)(5) of 
this section.
    (12) Monitoring requirements for PALs--(i) General requirements. (a) 
Each PAL permit must contain enforceable requirements for the monitoring 
system that accurately determines plantwide emissions of the PAL 
pollutant in terms of mass per unit of time. Any monitoring system 
authorized for use in the PAL permit must be based on sound science and 
meet generally acceptable scientific procedures for data quality and 
manipulation. Additionally, the information generated by such system 
must meet minimum legal requirements for admissibility in a judicial 
proceeding to enforce the PAL permit.
    (b) The PAL monitoring system must employ one or more of the four 
general monitoring approaches meeting the minimum requirements set forth 
in

[[Page 269]]

paragraphs (w)(12)(ii) (a) through (d) of this section and must be 
approved by the reviewing authority.
    (c) Notwithstanding paragraph (w)(12)(i)(b) of this section, you may 
also employ an alternative monitoring approach that meets paragraph 
(w)(12)(i)(a) of this section if approved by the reviewing authority.
    (d) Failure to use a monitoring system that meets the requirements 
of this section renders the PAL invalid.
    (ii) Minimum performance requirements for approved monitoring 
approaches. The following are acceptable general monitoring approaches 
when conducted in accordance with the minimum requirements in paragraphs 
(w)(12)(iii) through (ix) of this section:
    (a) Mass balance calculations for activities using coatings or 
solvents;
    (b) CEMS;
    (c) CPMS or PEMS; and
    (d) Emission factors.
    (iii) Mass balance calculations. An owner or operator using mass 
balance calculations to monitor PAL pollutant emissions from activities 
using coating or solvents shall meet the following requirements:
    (a) Provide a demonstrated means of validating the published content 
of the PAL pollutant that is contained in or created by all materials 
used in or at the emissions unit;
    (b) Assume that the emissions unit emits all of the PAL pollutant 
that is contained in or created by any raw material or fuel used in or 
at the emissions unit, if it cannot otherwise be accounted for in the 
process; and
    (c) Where the vendor of a material or fuel, which is used in or at 
the emissions unit, publishes a range of pollutant content from such 
material, the owner or operator must use the highest value of the range 
to calculate the PAL pollutant emissions unless the reviewing authority 
determines there is site-specific data or a site-specific monitoring 
program to support another content within the range.
    (iv) CEMS. An owner or operator using CEMS to monitor PAL pollutant 
emissions shall meet the following requirements:
    (a) CEMS must comply with applicable Performance Specifications 
found in 40 CFR part 60, appendix B; and
    (b) CEMS must sample, analyze, and record data at least every 15 
minutes while the emissions unit is operating.
    (v) CPMS or PEMS. An owner or operator using CPMS or PEMS to monitor 
PAL pollutant emissions shall meet the following requirements:
    (a) The CPMS or the PEMS must be based on current site-specific data 
demonstrating a correlation between the monitored parameter(s) and the 
PAL pollutant emissions across the range of operation of the emissions 
unit; and
    (b) Each CPMS or PEMS must sample, analyze, and record data at least 
every 15 minutes, or at another less frequent interval approved by the 
reviewing authority, while the emissions unit is operating.
    (vi) Emission factors. An owner or operator using emission factors 
to monitor PAL pollutant emissions shall meet the following 
requirements:
    (a) All emission factors shall be adjusted, if appropriate, to 
account for the degree of uncertainty or limitations in the factors' 
development;
    (b) The emissions unit shall operate within the designated range of 
use for the emission factor, if applicable; and
    (c) If technically practicable, the owner or operator of a 
significant emissions unit that relies on an emission factor to 
calculate PAL pollutant emissions shall conduct validation testing to 
determine a site-specific emission factor within 6 months of PAL permit 
issuance, unless the reviewing authority determines that testing is not 
required.
    (vii) A source owner or operator must record and report maximum 
potential emissions without considering enforceable emission limitations 
or operational restrictions for an emissions unit during any period of 
time that there is no monitoring data, unless another method for 
determining emissions during such periods is specified in the PAL 
permit.
    (viii) Notwithstanding the requirements in paragraphs (w)(12)(iii) 
through (vii) of this section, where an owner or operator of an 
emissions unit cannot demonstrate a correlation between the monitored 
parameter(s) and the PAL pollutant emissions rate at all operating 
points of the emissions unit,

[[Page 270]]

the reviewing authority shall, at the time of permit issuance:
    (a) Establish default value(s) for determining compliance with the 
PAL based on the highest potential emissions reasonably estimated at 
such operating point(s); or
    (b) Determine that operation of the emissions unit during operating 
conditions when there is no correlation between monitored parameter(s) 
and the PAL pollutant emissions is a violation of the PAL.
    (ix) Re-validation. All data used to establish the PAL pollutant 
must be re-validated through performance testing or other scientifically 
valid means approved by the reviewing authority. Such testing must occur 
at least once every 5 years after issuance of the PAL.
    (13) Recordkeeping requirements. (i) The PAL permit shall require an 
owner or operator to retain a copy of all records necessary to determine 
compliance with any requirement of paragraph (w) of this section and of 
the PAL, including a determination of each emissions unit's 12-month 
rolling total emissions, for 5 years from the date of such record.
    (ii) The PAL permit shall require an owner or operator to retain a 
copy of the following records, for the duration of the PAL effective 
peri